Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Feb. 28, 2018 | Jun. 27, 2018 | Aug. 31, 2017 | |
Document And Entity Information | |||
Entity Registrant Name | Norris Industries, Inc. | ||
Entity Central Index Key | 1,603,793 | ||
Document Type | 10-K | ||
Document Period End Date | Feb. 28, 2018 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --02-28 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 89,443,013 | ||
Trading Symbol | NRIS | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,018 |
Balance Sheets
Balance Sheets - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 |
Current Assets | ||
Cash | $ 244,997 | $ 76,365 |
Account receivable - oil & gas | 108,644 | 8,170 |
Deposit on purchase of oil & gas properties | 105,000 | |
Total Current Assets | 353,641 | 189,535 |
Oil and Gas Property - Full Cost Method | ||
Properties subject to amortization | 2,716,102 | 955,316 |
Less: accumulated depletion | (69,760) | (56,340) |
Total Oil and Gas Property, net | 2,646,342 | 898,976 |
Equipment, net | 12,646 | 17,546 |
Total Assets | 3,012,629 | 1,106,057 |
Current Liabilities | ||
Accounts payable and accrued expenses | 43,020 | 1,000 |
Accounts payable and accrued expenses - related parties | 20,412 | 379,428 |
Loan payable | 50,000 | |
Stock payable | 12,000 | |
Total Current Liabilities | 63,432 | 442,428 |
Convertible note payable - related party | 1,550,000 | |
Asset retirement obligations | 76,657 | 10,045 |
Total Liabilities | 1,690,089 | 452,473 |
Stockholders' Equity | ||
Preferred stock, value | ||
Common stock, $0.001 par value per share, 150,000,000 shares authorized; 89,443,013 and 48,696,013 shares issued and outstanding | 89,443 | 48,696 |
Additional paid-in capital | 5,967,483 | 2,791,328 |
Accumulated deficit | (4,735,386) | (2,186,440) |
Total Stockholder's Equity | 1,322,540 | 653,584 |
Total Liabilities and Stockholders' Equity | 3,012,629 | 1,106,057 |
Series A Convertible Preferred Stock [Member] | ||
Stockholders' Equity | ||
Preferred stock, value | 1,000 | |
Total Stockholder's Equity | $ 1,000 |
Balance Sheets (Parenthetical)
Balance Sheets (Parenthetical) - $ / shares | Feb. 28, 2018 | Feb. 28, 2017 |
Preferred stock, par value | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | ||
Preferred stock, shares outstanding | ||
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Common stock, shares issued | 89,443,013 | 48,696,013 |
Common stock, shares outstanding | 89,443,013 | 48,696,013 |
Series A Convertible Preferred Stock [Member] | ||
Preferred stock, par value | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 1,000,000 | 0 |
Preferred stock, shares outstanding | 1,000,000 | 0 |
Statements of Operations
Statements of Operations - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Revenues | ||
Total Revenues | $ 131,943 | $ 149,351 |
Operating Expenses | ||
Lease operating expenses | 131,626 | 188,150 |
General and administrative expenses | 1,273,147 | 1,706,570 |
Depletion and accretion | 24,146 | 23,373 |
Total Operating Expenses | 1,428,919 | 1,918,093 |
Loss from Operations | (1,296,976) | (1,768,742) |
Other Income (Expenses) | ||
Gain on sale of property | 20,324 | |
Loss on extinguishment of debt | (1,228,322) | |
Interest expense | (23,648) | (1,000) |
Total Other Income (Expense) | (1,251,970) | 19,676 |
Net Loss | $ (2,548,946) | $ (1,749,418) |
Net loss per common share - basic and diluted | $ (0.03) | $ (0.04) |
Weighted average number of common shares outstanding - basic and diluted | 89,211,013 | 46,416,182 |
Oil and Gas Sales [Member] | ||
Revenues | ||
Total Revenues | $ 131,943 | $ 104,351 |
Service Income [Member] | ||
Revenues | ||
Total Revenues | $ 45,000 |
Statement of Changes in Stockho
Statement of Changes in Stockholders' Equity - USD ($) | Series A Convertible Preferred Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated Deficit [Member] | Total |
Balance at Feb. 29, 2016 | $ 44,315 | $ 1,367,575 | $ (437,022) | $ 974,868 | |
Balance, shares at Feb. 29, 2016 | 44,314,964 | ||||
Common stock issued for cash | $ 3,519 | 997,681 | 1,001,200 | ||
Common stock issued for cash, shares | 3,518,949 | ||||
Stock-based compensation | $ 862 | 426,072 | 426,934 | ||
Stock-based compensation, shares | 862,100 | ||||
Net loss | (1,749,418) | (1,749,418) | |||
Balance at Feb. 28, 2017 | $ 48,696 | 2,791,328 | (2,186,440) | 653,584 | |
Balance, shares at Feb. 28, 2017 | 48,696,013 | ||||
Common stock issued for cash | $ 34,520 | 330,480 | 365,000 | ||
Common stock issued for cash, shares | 34,520,000 | ||||
Stock-based compensation | $ 315 | 482,837 | 483,152 | ||
Stock-based compensation, shares | 315,000 | ||||
Common stock issued for settlement of stock payable | $ 12 | 11,988 | 12,000 | ||
Common stock issued for settlement of stock payable, shares | 12,000 | ||||
Common stock issued for loan payable | $ 5,900 | 1,601,850 | 1,607,750 | ||
Common stock issued for loan payable, shares | 5,900,000 | ||||
Preferred stock issued for loan payable | $ 1,000 | 749,000 | 750,000 | ||
Preferred stock issued for loan payable, shares | 1,000,000 | ||||
Net loss | (2,548,946) | (2,548,946) | |||
Balance at Feb. 28, 2018 | $ 1,000 | $ 89,443 | $ 5,967,483 | $ (4,735,386) | $ 1,322,540 |
Balance, shares at Feb. 28, 2018 | 1,000,000 | 89,443,013 |
Statements of Cash Flows
Statements of Cash Flows - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Cash Flow from Operating Activities | ||
Net loss | $ (2,548,946) | $ (1,749,418) |
Adjustments to reconcile net loss to net cash from operating activities: | ||
Depletion and accretion | 24,146 | 28,313 |
Stock-based compensation | 483,152 | 426,934 |
Loss on extinguishment of debt | 1,228,322 | |
Gain on sale of oil and gas property | (20,324) | |
Loss on write-off of investment | 5,000 | 30,000 |
Changes in operating assets and liabilities: | ||
Accounts receivable - oil & gas | (100,474) | (8,170) |
Accounts payable and accrued expenses | 42,020 | (12,138) |
Accounts payable and accrued expenses - related parties | 20,412 | |
Net Cash Used in Operating Activities | (846,368) | (1,304,803) |
Cash Flow from Investing Activities | ||
Deposit on purchase of oil and gas properties | (135,000) | |
Sale of oil and gas properties | 70,000 | |
Purchase of oil and gas properties | (1,600,000) | |
Net Cash used in Investing Activities | (1,600,000) | (65,000) |
Cash Flow from Financing Activities | ||
Proceeds from convertible note payable - related party | 2,300,000 | 50,000 |
Payment on loan payable | (50,000) | |
Payments on related party advances | (159,260) | |
Common stock issued for cash | 365,000 | 1,001,200 |
Proceeds from issuance of stock payable | 12,000 | |
Net Cash provided by Financing Activities | 2,615,000 | 903,940 |
Net Decrease in Cash | 168,632 | (465,863) |
Cash - beginning of year | 76,365 | 542,228 |
Cash - end of year | 244,997 | 76,365 |
Supplemental Cash Flow Information | ||
Cash paid for income taxes | ||
Cash paid for interest | 4,000 | |
Noncash Investing and Financing Activities | ||
Reclassification of pre-acquisition costs to oil and gas properties | 100,000 | |
Common stock issued for conversion of loan | 1,607,750 | |
Issuance of common stock for stock payable | 12,000 | |
Series A Convertible Preferred Stock issued for conversion of loan | 750,000 | |
Change of estimate in asset retirement obligation | 31,081 | |
Asset retirement obligation from acquisition of oil and gas properties | $ 29,705 |
Organization, Nature of Operati
Organization, Nature of Operations and Summary of Significant Accounting Policies | 12 Months Ended |
Feb. 28, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization, Nature of Operations and Summary of Significant Accounting Policies | Note 1 – Organization, Nature of Operations and summary of Significant Accounting Policies Norris Industries, Inc. (“NRIS” or the “Company”) (formerly International Western Petroleum, Inc.), was incorporated on February 19, 2014 as a Nevada corporation. The Company was formed to conduct operations in the oil and gas industry. The Company’s principal operating properties are in the Ellenberger formation in Coleman County, as well as the Jack and Palo-Pinto Counties. The Company’s production operations are all located in the State of Texas. On April 25, 2018, the Company incorporated a Texas registered subsidiary, Norris Petroleum, Inc., as its own operating entity. Basis of Presentation The accompanying financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”). Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expense during the period. Actual results could differ from those estimates. Cash and Cash Equivalents The Company considers all highly liquid investments purchased with an original maturity of the year or less to be cash equivalents. The Company has not experienced any losses on its deposits of cash and cash equivalents . Oil and Gas Properties, Full Cost Method The Company follows the full cost method of accounting for its oil gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations. Depletion and depreciation of proved oil properties will be calculated on the units-of-production method based upon estimates of proved reserves. Such calculations include the estimated future costs to develop proved reserves. Costs of unproved properties are not included in the costs subject to depletion. These costs are assessed periodically for impairment. At the end of each quarter, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future after-tax net revenues from proved properties, after giving effect to cash flow hedge positions, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects. Costs in excess of the present value of estimated future net revenues are charged to impairment expense. This limitation is known as the “ceiling test,” and is based on SEC rules for the full cost oil and gas accounting method. The Company capitalizes pre-acquisition costs directly identifiable with specific properties when the acquisition of such properties is probable. Capitalized pre-acquisition costs are presented in the balance sheet. Equipment Equipment is stated at cost less accumulated depreciation. 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. Income Taxes Income taxes are accounted for in accordance with the provisions of ASC Topic No. 740. Deferred tax assets and liabilities are recognized 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 years 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 income in the period that includes the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amounts expected to be realized. Revenue Recognition All revenue is recognized when persuasive evidence of an arrangement exists, the service or sale is complete, the price is fixed or determinable and collectability is reasonably assured. Revenue is derived from the sale of crude oil and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected. Share-based Compensation The Company estimates the fair value of each share-based compensation award at the grant date by using the Black-Scholes option pricing model. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest. Excess tax benefits, if any, are recognized as an addition to paid-in capital. Net Loss per Common Share Basic net loss per common share amounts are computed by dividing the net loss available to Norris Industries, Inc. shareholders by the weighted average number of common shares outstanding over the reporting period. In periods in which the Company reports a net loss, dilutive securities are excluded from the calculation of diluted earnings per share as the effect would be anti-dilutive. For the years ended February 28, 2018 and 2017, there were outstanding options to purchase 1,440,000 and 0 of the Company’s common stock, respectively, were excluded from the calculation of diluted net loss per share, as the inclusion of these shares would be anti-dilutive. 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 maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed by the Federal Deposit Insurance Corporation (“FDIC”). At February 28, 2018, $0 of the Company’s cash balances was uninsured. The Company has not experienced any losses on such accounts. Subsequent Events The Company has evaluated all transactions through the financial statement issuance date for subsequent event disclosure consideration. Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases In September 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses In May 2017, the FASB issued ASU 2017-09, Modification Accounting for Share-Based Payment Arrangements |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Feb. 28, 2018 | |
Extractive Industries [Abstract] | |
Oil and Gas Properties | Note 2 – Oil and Gas Properties The following table summarizes the Company’s oil and gas activities by classification for the years ended February 28, 2018 and 2017: February 29, 2016 Additions Sales February 28, 2017 Oil and gas properties, subject to depletion $ 996,954 $ - $ (50,076 ) $ 946,878 Asset retirement costs 8,438 - - 8,438 Accumulated depletion (34,279 ) (22,461 ) 400 (56,340 ) Total oil and gas assets $ 971,113 $ (22,461 ) $ (49,676 ) $ 898,976 February 28, 2017 Additions Reclassifications February 28, 2018 Oil and gas properties, subject to depletion $ 946,878 $ 1,700,000 $ - $ 2,646,878 Asset retirement costs 8,438 60,786 - 69,224 Accumulated depletion (56,340 ) (13,420 ) - (69,760 ) Total oil and gas assets $ 898,976 $ 1,747,366 $ - $ 2,646,342 The depletion recorded for production on proved properties for the years ended February 28, 2018 and 2017, amounted to $13,420 and $22,461, respectively. King County Properties As of December 6, 2016, the Company acquired, in a series of payments originally classified as deposits that totaled $100,000, the Ratliff leases, totaling 640 acres. The acquisition was completed in the current year. This lease also consisted of a 3D Seismic survey data for 340 acres of the leasehold acreage acquired in King County, Texas. This acquisition represented a 100% working interest, with a 70% net revenue interest on such leasehold acreages. The following table summarizes the purchase price and allocation of the purchase price to the net assets acquired in connection with the acquisition described above: Consideration Given Cash paid $ 100,000 Net Assets Acquired Oil and gas properties $ 105,642 Asset retirement obligation (5,642 ) Total purchase price $ 100,000 Jack County and Palo Pinto County Properties On December 28, 2017, the Company paid $1.6 million for the rights to 11 oil and gas leases, totaling 2,790.9 acres. These leases are located in the Jack County and Palo Pinto County in Texas. The wells located on these leases have existing production and the Company plans to invest additional funds to further develop these oil and gas properties. The following tables summarize the purchase price and allocation of the purchase price to the net assets acquired in connection with the Acquisition: Consideration Given Cash paid $ 1,600,000 Net Assets Acquired Oil and gas properties $ 1,624,063 Asset retirement obligation (24,063 ) Total purchase price $ 1,600,000 |
Equipment
Equipment | 12 Months Ended |
Feb. 28, 2018 | |
Property, Plant and Equipment [Abstract] | |
Equipment | Note 3 – Equipment The Company’s fixed assets consisted of a used vehicle and has an estimated useful life of five years. Fixed assets consists of the following at February 28, 2018 and 2017: 2018 2017 Vehicle $ 24,500 $ 24,500 Accumulated depreciation (11,854 ) (6,954 ) Total $ 12,646 $ 17,546 The Company recorded depreciation expense of $4,900 and $4,940, respectively, during the years ended February 28, 2018 and 2017. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Feb. 28, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 4 – Asset Retirement Obligations The following table summarizes the change in the Company’s asset retirement obligations during the year ended February 28, 2018: Asset retirement obligations as of February 28, 2017 $ 10,045 Additions 29,705 Current year revision of previous estimates 31,081 Accretion during the year ended February 28, 2018 5,826 Asset retirement obligations as of February 28, 2018 $ 76,657 During the years ended February 28, 2018 and 2017, the Company recognized accretion expense of $5,826 and $912, respectively. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Feb. 28, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 5 – Related Party Transactions $750,000 Loan Payable to JBB Partners, Inc. (“JBB”) On April 7, 2017, the Company entered into a secured promissory note (the “Secured Promissory Note”) with JBB, an entity owned by the Company’s CEO and majority shareholder. Pursuant to the terms of the Secured Promissory Note, the Company borrowed from JBB $200,000 (the “Loan”). The Loan was funded on April 11, 2017. The Loan was secured by all of the Company’s assets and until August 2, 2017 was additionally secured by 17,920,000 shares of the Company’s common stock then owned by two of the then officers of the Company. The Loan carried interest at the rate of 3% per annum and the maturity date was April 7, 2018. On July 27, 2017, to be effective as of August 2, 2017, JBB and the Company: (a) modified the Secured Promissory Note and restated it to increase the loan principal to an aggregate of $750,000, which includes the advance made on April 11, 2017, and (b) modified and added certain other provisions, including elimination of the share collateral that secured the Loan, changing the maturity date to July 27, 2018, and adding a provision to automatically convert the outstanding principal and interest into 1,000,000 shares of Series A Convertible Preferred Stock. The Company had a shareholder meeting in November 2017, in which it approved a name change and new corporation charter, those changes became effective on February 21, 2018, with its name changed to Norris Industries, an increase in the number of authorized common shares issuable to 150,000,000 shares, and authorized 20,000,000 shares of preferred stock, of which 1,000,000 Series A Preferred shares were issued to JBB Partners, Inc. in exchange for the $750,000 of prior debt and accrued interest outstanding (See Note 9). During the year ended February 28, 2018, the Company recognized interest expense of $12,513 related to the $750,000 loan payable to JBB Partners, Inc. $1,550,000 Promissory Note to JBB On December 28, 2017, the Company borrowed $1,550,000 from JBB to complete the purchases of a series of oil and leases. The loan has an interest rate of 3% per annum, a maturity date of December 28, 2018 and is secured by all assets of the Company. The loan is convertible to the Company’s common stock at the conversion rate of $0.20 per share. On June 13, 2018, the Company entered into an amendment of its promissory note to JBB to extend the maturity date to September 30, 2019. During the year ended February 28, 2018, the Company recognized interest expense of $7,899 related to the $1,550,000 promissory note to JBB. The balance of this promissory note was $1,550,000 at February 28, 2018, plus interest that is due at maturity. Due to related party From time to time, the Company received advances from a related party, International Western Oil Corporation (“IWO”), an entity owned by the former controlling shareholders of the Company, to fund its operations. As of February 28, 2017, the Company had an outstanding accounts payable and accrued expenses due to IWO in the amount $379,428. On May 30, 2017, IWO sold its receivable from the Company to Riggs Capital, Inc. As of February 28, 2018, the Company did not have any payable remaining outstanding to IWO. |
Settlement of Debt
Settlement of Debt | 12 Months Ended |
Feb. 28, 2018 | |
Debt Disclosure [Abstract] | |
Settlement of Debt | Note 6 – Settlement of Debt On May 30, 2017, IWO sold its receivable from the Company in the amount of $379,428 to Riggs Capital, Inc. an unrelated third party of the Company. The debt was unsecured, had no stated interest rate, was due on demand and had no conversion features. On August 2, 2017, the Company and Riggs Capital, Inc. consummated a Debt Conversion Agreement to convert the outstanding debt of $379,428 into 5,900,000 shares of Common Stock which were distributed to Riggs Capital, Inc. and its related party, Patrick Riggs. The Debt Conversion Agreement provided for a one-year lock-up on the sale of shares issued in the transaction. The Company recorded a loss on extinguishment of debt of $1,228,322 to recognize the difference between the reacquisition price, (the fair value of the stock issued) and the net carrying amount of the extinguished debt. ASC Topic 470-50-40 provides for the difference between the net carrying amount of the extinguished debt and the reacquisition price be recognized currently in the period of extinguishment. |
Income Taxes
Income Taxes | 12 Months Ended |
Feb. 28, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 7 – Income Taxes Due to the Company’s net losses, there were no provisions for income taxes for the years ended February 28, 2018 and 2017. The difference between the income tax expense of zero shown in the statement of operations and pre-tax book net loss times the federal statutory rate of 32.7% and 34% for the years ended February 28, 2018 and 2017, respectively, are summarized as follows: 2018 2017 Pretax book income $ (833,505 ) $ (594,802 ) Permanent differences: Stock-based compensation 78,995 72,579 Loss on settlement of debt 200,831 - Change in valuation allowance 243,412 629,562 Change in the effective rates 331,363 - Other adjustments (21,096 ) (107,339 ) Total tax expense $ - $ - Deferred income tax assets for the years ended February 28, 2018 and 2017 are as follows: Deferred Tax Assets 2018 2017 Net operating losses carry forwards $ 1,444,810 $ 1,204,194 Difference in depletion, depreciation and capitalization method (3,777 ) (6,573 ) Total deferred tax assets 1,441,033 1,197,621 Less valuation allowance (1,441,033 ) (1,197,621 ) Total deferred tax assets $ - $ - In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of 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. Based on the available objective evidence, management believes it is more likely than not that the net deferred tax assets will not be fully realizable. Accordingly, management has applied a full valuation allowance against its net deferred tax assets at February 28, 2018 and 2017. The net change in the total valuation allowance from February 28, 2017 and February 28, 2018, was a decrease of $243,412. 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 February 28, 2018 and 2017, the Company did not have any significant uncertain tax positions or unrecognized tax benefits. The Company incurred interest expense of $1,000 and $0 penalties was recognized for the year ended February 28, 2017. As of February 28, 2018, the Company has federal net operating loss carryforwards of approximately $1,441,033 for federal and state tax purposes, respectively, which if not utilized, will expire beginning in 2038, respectively, for both federal and state purposes. 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. The Company experienced an “ownership change” within the meaning of IRC Section 382 during the year ended February 28, 2018. As a result, certain limitations apply to the annual amount of net operating losses that can be used to offset post ownership change taxable income. The Company has estimated that $1.1 million of its pre-ownership change net operating loss could potentially be lost due to the IRC Section 382 limitation. Tax Cuts and Jobs Act On December 22, 2017, the U.S. Government enacted comprehensive tax legislation referred to as the Tax Cuts and Jobs Act (the “Act”). The Act makes broad and complex changes to the U.S. tax code, including but not limited to, reducing the U.S. federal corporate rate from 35% to 21%, allowing full expensing of qualified property acquired and placed in service after September 27, 2017 and imposing new limits on the deduction of net operating losses, executive compensation and net interest expense. The rate change, along with certain immaterial changes in tax basis resulting from the 2017 Tax Act, resulted in a reduction of the Company’s deferred tax asset $360,842 and a corresponding reduction in the valuation allowance. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Feb. 28, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 8 – Commitments and Contingencies Office Lease In March 2015, the Company entered into an amendment to extend the term of its office lease to August 31, 2018. The obligation under this lease extension for the remainder of its term is $13,400. During the year ended February 28, 2018, the Company had total rent expense of $37,588. 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 King County, Texas lease acreage, 640 acres are due to expire in June 2021. The Company plans to hold significantly all of this acreage through a program of drilling and completing producing wells. Where the Company is not able to drill and complete a well before lease expiration, the Company may seek to extend leases where able. |
Equity Transactions
Equity Transactions | 12 Months Ended |
Feb. 28, 2018 | |
Equity [Abstract] | |
Equity Transactions | Note 9 – Equity Transactions On February 21, 2018, the Company effected an increase in the Company’s authorized shares of stock from 90,000,000 to 170,000,000, of which 150,000,000 shares are designated as common stock, par value $0.0001 per share, and 20,000,000 shares are designated as preferred stock, par value $0.0001 per share, and (3) create a single class of “blank check” Preferred Stock for the issuance of up to 20,000,000 shares of Preferred Stock, having such terms, rights and features as may be determined by the board of directors of the Company from time to time. Preferred Stock On February 21, 2018, the Company filed a Certificate of Designation with the Secretary of State of Nevada to create the Series A Convertible Preferred Stock of the Company and fulfill the Company’s obligations under the $750,000 Loan Payable to JBB described in Note 6. The Series A Convertible Preferred Stock has certain dividend, liquidation, voting and conversion rights. When, and as declared by the Company’s Board of Directors, the holders of Series A Convertible Preferred Stock may be entitled to participate prior to any dividends paid on the Company’s common stock. The Series A Convertible Preferred Stock Original Issuance Price is $0.75 per share. In the event of any liquidation, dissolution or winding up of the Company or any Deemed Liquidation Event (as defined in the Certificate of Designation), the holders of Series A Convertible Preferred Stock would be entitled to receive, prior to and in preference to the holders of common stock, an amount per share of Series A Preferred Stock equal to three (3) times the Series A Preferred Stock Original Issue Price plus any declared but unpaid dividends thereon, which is the full principal amount of the $750,000 Loan Payable to JBB. Holders of the Series A Convertible Preferred Stock have the right to convert shares of Series A Convertible Preferred Stock, at any time and from time to time, into such number of fully paid and non-assessable shares of common stock as is determined by the number of shares Series A Convertible Preferred Stock, divided by the product of (i) the Preferred Stock Conversion Price in effect at the time of conversion and (ii) 0.02. The “Preferred Stock Conversion Price” shall initially be equal to $0.75 will equal 666,666.66 shares of common stock. Such Preferred Stock Conversion Price shall be subject to adjustment as in the event of stock split, merger, reorganization and certain dividend and distribution. There is no mandatory conversion or redemption right by the Company. As of February 28, 2018, there were 1,000,000 shares of Series A Convertible Preferred Stock issued and outstanding. Common Stock During the year ended February 28, 2017: - the Company sold 3,518,948 shares of its common stock for total cash proceeds of $1,001,200; and - the Company issued 862,100 shares, valued at their fair value of $426,934, of its common stock for services. During the year ended February 28, 2018: - the Company sold 34,520,000 shares of its common stock for total cash proceeds of $365,000; - the Company issued 12,000 shares of its common stock to settle $12,000 of stock payable; - the Company issued 315,000 shares, valued at their fair value of $483,152, of its common stock for stock-based compensation; - on August 2, 2017, Ross Henry Ramsey, former CEO of the Company, and Benjamin Tran, former Chairman of the Company, sold 17,920,000 shares of common stock and 12,000,000 shares of common stock, respectively, to JBB Partners, Inc. Mr. Patrick Norris is the principal of JBB Partners, Inc. The Company’s related party, International Western Oil Corporation, also sold 500,000 shares of the Company’s common stock to Mr. Patrick Norris. At the same time, Mr. Norris was appointed the new CEO, President, CFO, Secretary and a director of the Company. Mr. Ramsey continued as a director of the Company, and Mr. Tran resigned as a director of the Company effective September 15, 2017. A change of control event occurred as a result of these transactions; and - on August 2, 2017, the Company and Riggs Capital, Inc. consummated a Debt Conversion Agreement to convert its outstanding debt of $379,428 into 5,900,000 shares of common stock which were distributed to Riggs Capital, Inc. and its related party, Patrick Riggs. The Debt Conversion Agreement provided for a one-year lock-up on the sale of shares issued in the transaction. The Company recorded a loss on extinguishment of debt of $1,228,322 to recognize the difference between the reacquisition price, (the fair value of the stock issued) and the net carrying amount of the extinguished debt. ASC Topic 470-50-40 provides for the difference between the net carrying amount of the extinguished debt and the reacquisition price be recognized currently in the period of extinguishment. Stock Options During the year ended February 28, 2018, the Company granted two of its officers options to purchase a total of 1,440,000 shares the Company’s common stock with an exercise price of $0.01 per share, a term of 2 years until August 3, 2019, and a vesting period of 2 years. The options have an aggregate fair value of $431,956 that was calculated using the Black-Scholes option-pricing model. Variables used in the Black-Scholes option-pricing model include: (1) discount rate of 1.34%; (2) expected life of 2 years; (3) expected volatility of 482.51%; and (4) zero expected dividends. The fair value of all options issued and outstanding are being amortized over their respective vesting periods. These options had an intrinsic value of $417,600 as of February 28, 2018. During the year ended February 28, 2018, the Company recorded total option expense of $126,000 related to the vesting of these options. The unrecognized compensation expense on these options at February 28, 2018 was approximately $306,000. As of February 28, 2018, these options have a remaining life of 1.43 years. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Feb. 28, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 10 – Subsequent Events On June 26, 2018, the Company and JBB have entered into a modification of the existing Secured Promissory Note originally dated December 28, 2017 (‘Loan Note”), to add provisions to permit the Company to obtain advances under the Loan Note up to a maximum of $1,000,000. The Company may request an advance in an amount of $100,000 no more frequently than every 30 days, provided that it provides a description of the use of proceeds for the advance reasonably acceptable to JBB, and the Company is not otherwise in default of the Loan Note. The original loan amount and the advances are secured by all the assets of the Company and are convertible into common stock of the Company at the rate of $0.20 per share, subject to adjustment for any reverse and forward stock splits. The Loan Note may be repaid at any time, without penalty, however, any advance that is repaid before maturity may not be re-borrowed as a further advance. The maturity date of the original amount and all the advances is September 30, 2019. |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures (Unaudited) | 12 Months Ended |
Feb. 28, 2018 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Gas Disclosures (Unaudited) | Note 11 – Supplemental Oil and Gas Disclosures (Unaudited) Capitalized Costs Relating to Oil and Gas Producing Activities The estimates of proved oil and gas reserves utilized in the preparation of these statements were prepared by Bryant M. Mook for year ended February 28, 2018 and by Ralph E. Davis for year ended February 28, 2017, using reserve definitions and pricing requirements prescribed by the SEC. The Company used a combination of production performance and offset analogies, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or developmental plans, to estimate its reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to the proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since February 28, 2018. The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of the Company’s proved reserves are proved developed non-producing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced. All of the Company’s reserves are located in the United States. February 28, 2018 February 28, 2017 Proved oil and gas properties $ 2,716,102 $ 955,316 Unproved oil and gas properties - - Accumulated depreciation, depletion and amortization (69,760 ) (56,340 ) Total acquisition, development and exploration costs $ 2,646,342 $ 898,976 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities At February 28, 2018 and 2017, unevaluated costs of $0 were excluded from the depletion base. February 28, 2018 February 28, 2017 Acquisition of properties - proved $ 1,605,000 $ 381,067 Acquisition of properties - unproved - - Exploration costs - 88,000 Development costs - 536,325 Disposition/sale (5,000 ) (50,076 ) Total costs incurred $ 1,600,000 $ 955,316 Estimated Quantities of Proved Oil and Gas Reserves The following table sets forth proved oil and gas reserves together with the changes therein, proved developed reserves and proved undeveloped reserves for the years ended February 28, 2018 and 2017. Units of oil are in thousands of barrels (“MBbls”) and units of gas are in millions of cubic feet (“MMcf”). Gas is converted to barrels of oil equivalents (“MBoe”) using a ratio of six Mcf of gas per Bbl of oil. 2018 2017 Oil Gas BOE Oil Gas BOE Proved reserves: Beginning of year 138 103 155 142 115 161 Revisions (33 ) (91 ) (48 ) (2 ) (4 ) (3 ) Extensions and discoveries - - - - - - Purchases of minerals-in-place 94 4,617 864 - - - Sales of minerals-in-place - - - - - - Production (2 ) (20 ) (5 ) (2 ) (8 ) (3 ) End of year 197 4,609 966 138 103 155 Proved developed reserves: Beginning of year 12 38 18 12 38 18 End of year 59 861 203 8 26 12 Proved not producing reserves: Beginning of year 54 14 57 54 14 57 End of year 138 3,747 763 54 14 56 Proved undeveloped reserves: Beginning of year 76 64 86 76 63 86 End of year - - - 76 63 87 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by the Company’s independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of future production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties. Future cash inflows for 2018 were computed by applying the average price for the year to the year-end quantities of proved reserves. The 2018 average price for the year was calculated using the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period. Adjustment in this calculation for future price changes is limited to those required by contractual arrangements in existence at the end of each reporting year. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing and producing proved oil and natural gas reserves at the end of the year, based on year-end costs, assuming continuation of year-end economic conditions. Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented, and to the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties, after consideration of available net operating loss and percentage depletion carryovers. Discounted future net cash flows have been calculated using a ten percent discount factor. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The estimated present value of future cash flows relating to prove reserves is extremely sensitive to prices used at any measurement period. The prices used for each commodity for the years ended February 28, 2018 and 2017 as adjusted, were as follows: Oil (Bbl) Using NYMEX WTI Gas (Mcf) Using NYMEX Henry Hub 2018 (average price) $ 53.49 $ 3.00 2017 (average price) $ 43.05 $ 1.55 The information provided in the tables set out below does not represent management’s estimate of the Company’s expected future cash flows or of the value of the Company’s proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under ASC No. 932 requires assumptions as to the timing and amount of future development and production costs. The calculations should not be relied upon as an indication of the Company’s future cash flows or of the value of its oil and gas reserves. The following table sets forth the standardized measure of discounted future net cash flows relating to proven reserves for the years ended February 28, 2018 and 2017 respectively (stated in thousands): 2018 2017 Future cash inflows $ 24,391 $ 6,113 Future costs: Production costs (4,530 ) (718 ) Future tax expense (2,209 ) (439 ) Future development costs (950 ) (1,093 ) Future net cash flows 16,702 3,863 10% annual discount for estimated timing of cash flows (8,755 ) (1,319 ) Standardized measure of discounted net cash flows $ 7,947 $ 2,544 Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows at 10% per annum for the years ended February 28, 2018 and 2017, respectively (stated in thousands): 2018 2017 Increase (decrease): Beginning of year $ 2,544 $ 2,369 Sales of oil produced, net of production costs 1,595 59 Net changes in sales and transfer prices and in production costs and production costs related to future production (10,443 ) 5,103 Previously estimated development costs incurred during the period - - Changes in future development costs 950 1,093 Revisions of previous quantity estimates due to prices and performance (649 ) (140 ) Accretion of discount 254 237 Discoveries, net of future production and development costs associated with these extensions and discoveries - - Purchases and sales of minerals in place 6,894 - Timing and other 6,802 (6,177 ) End of year $ 7,947 $ 2,544 |
Organization, Nature of Opera18
Organization, Nature of Operations and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Feb. 28, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”). |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expense during the period. Actual results could differ from those estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid investments purchased with an original maturity of the year or less to be cash equivalents. The Company has not experienced any losses on its deposits of cash and cash equivalents . |
Oil and Gas Properties, Full Cost Method | Oil and Gas Properties, Full Cost Method The Company follows the full cost method of accounting for its oil gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations. Depletion and depreciation of proved oil properties will be calculated on the units-of-production method based upon estimates of proved reserves. Such calculations include the estimated future costs to develop proved reserves. Costs of unproved properties are not included in the costs subject to depletion. These costs are assessed periodically for impairment. At the end of each quarter, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future after-tax net revenues from proved properties, after giving effect to cash flow hedge positions, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects. Costs in excess of the present value of estimated future net revenues are charged to impairment expense. This limitation is known as the “ceiling test,” and is based on SEC rules for the full cost oil and gas accounting method. The Company capitalizes pre-acquisition costs directly identifiable with specific properties when the acquisition of such properties is probable. Capitalized pre-acquisition costs are presented in the balance sheet. |
Equipment | Equipment Equipment is stated at cost less accumulated depreciation. 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. |
Income Taxes | Income Taxes Income taxes are accounted for in accordance with the provisions of ASC Topic No. 740. Deferred tax assets and liabilities are recognized 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 years 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 income in the period that includes the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amounts expected to be realized. |
Revenue Recognition | Revenue Recognition All revenue is recognized when persuasive evidence of an arrangement exists, the service or sale is complete, the price is fixed or determinable and collectability is reasonably assured. Revenue is derived from the sale of crude oil and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected. |
Share-based Compensation | Share-based Compensation The Company estimates the fair value of each share-based compensation award at the grant date by using the Black-Scholes option pricing model. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest. Excess tax benefits, if any, are recognized as an addition to paid-in capital. |
Net Loss Per Common Share | Net Loss per Common Share Basic net loss per common share amounts are computed by dividing the net loss available to Norris Industries, Inc. shareholders by the weighted average number of common shares outstanding over the reporting period. In periods in which the Company reports a net loss, dilutive securities are excluded from the calculation of diluted earnings per share as the effect would be anti-dilutive. For the years ended February 28, 2018 and 2017, there were outstanding options to purchase 1,440,000 and 0 of the Company’s common stock, respectively, were excluded from the calculation of diluted net loss per share, as the inclusion of these shares would be anti-dilutive. |
Concentrations of Credit Risk | 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 maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed by the Federal Deposit Insurance Corporation (“FDIC”). At February 28, 2018, $0 of the Company’s cash balances was uninsured. The Company has not experienced any losses on such accounts. |
Subsequent Events | Subsequent Events The Company has evaluated all transactions through the financial statement issuance date for subsequent event disclosure consideration. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers In February 2016, the FASB issued ASU 2016-02, Leases In September 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses In May 2017, the FASB issued ASU 2017-09, Modification Accounting for Share-Based Payment Arrangements |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 12 Months Ended |
Feb. 28, 2018 | |
Summary of Oil and Gas Activities | The following table summarizes the Company’s oil and gas activities by classification for the years ended February 28, 2018 and 2017: February 29, 2016 Additions Sales February 28, 2017 Oil and gas properties, subject to depletion $ 996,954 $ - $ (50,076 ) $ 946,878 Asset retirement costs 8,438 - - 8,438 Accumulated depletion (34,279 ) (22,461 ) 400 (56,340 ) Total oil and gas assets $ 971,113 $ (22,461 ) $ (49,676 ) $ 898,976 February 28, 2017 Additions Reclassifications February 28, 2018 Oil and gas properties, subject to depletion $ 946,878 $ 1,700,000 $ - $ 2,646,878 Asset retirement costs 8,438 60,786 - 69,224 Accumulated depletion (56,340 ) (13,420 ) - (69,760 ) Total oil and gas assets $ 898,976 $ 1,747,366 $ - $ 2,646,342 |
King County Properties [Member] | |
Schedule of Purchase Price and its Allocation to Net Assets Acquired | The following table summarizes the purchase price and allocation of the purchase price to the net assets acquired in connection with the acquisition described above: Consideration Given Cash paid $ 100,000 Net Assets Acquired Oil and gas properties $ 105,642 Asset retirement obligation (5,642 ) Total purchase price $ 100,000 |
Jack County and Palo Pinto County Properties [Member] | |
Schedule of Purchase Price and its Allocation to Net Assets Acquired | The following tables summarize the purchase price and allocation of the purchase price to the net assets acquired in connection with the Acquisition: Consideration Given Cash paid $ 1,600,000 Net Assets Acquired Oil and gas properties $ 1,624,063 Asset retirement obligation (24,063 ) Total purchase price $ 1,600,000 |
Equipment (Tables)
Equipment (Tables) | 12 Months Ended |
Feb. 28, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Fixed Assets | Fixed assets consists of the following at February 28, 2018 and 2017: 2018 2017 Vehicle $ 24,500 $ 24,500 Accumulated depreciation (11,854 ) (6,954 ) Total $ 12,646 $ 17,546 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Feb. 28, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligation | The following table summarizes the change in the Company’s asset retirement obligations during the year ended February 28, 2018: Asset retirement obligations as of February 28, 2017 $ 10,045 Additions 29,705 Current year revision of previous estimates 31,081 Accretion during the year ended February 28, 2018 5,826 Asset retirement obligations as of February 28, 2018 $ 76,657 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Feb. 28, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Expense Reconciliation | 2018 2017 Pretax book income $ (833,505 ) $ (594,802 ) Permanent differences: Stock-based compensation 78,995 72,579 Loss on settlement of debt 200,831 - Change in valuation allowance 243,412 629,562 Change in the effective rates 331,363 - Other adjustments (21,096 ) (107,339 ) Total tax expense $ - $ - |
Schedule of Deferred Income Tax Assets | Deferred income tax assets for the years ended February 28, 2018 and 2017 are as follows: Deferred Tax Assets 2018 2017 Net operating losses carry forwards $ 1,444,810 $ 1,204,194 Difference in depletion, depreciation and capitalization method (3,777 ) (6,573 ) Total deferred tax assets 1,441,033 1,197,621 Less valuation allowance (1,441,033 ) (1,197,621 ) Total deferred tax assets $ - $ - |
Supplemental Oil and Gas Disc23
Supplemental Oil and Gas Disclosures (Tables) | 12 Months Ended |
Feb. 28, 2018 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities | All of the Company’s reserves are located in the United States. February 28, 2018 February 28, 2017 Proved oil and gas properties $ 2,716,102 $ 955,316 Unproved oil and gas properties - - Accumulated depreciation, depletion and amortization (69,760 ) (56,340 ) Total acquisition, development and exploration costs $ 2,646,342 $ 898,976 |
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities | February 28, 2018 February 28, 2017 Acquisition of properties - proved $ 1,605,000 $ 381,067 Acquisition of properties - unproved - - Exploration costs - 88,000 Development costs - 536,325 Disposition/sale (5,000 ) (50,076 ) Total costs incurred $ 1,600,000 $ 955,316 |
Schedule of Estimated Quantities of Proved Oil and Gas Reserves | The following table sets forth proved oil and gas reserves together with the changes therein, proved developed reserves and proved undeveloped reserves for the years ended February 28, 2018 and 2017. Units of oil are in thousands of barrels (“MBbls”) and units of gas are in millions of cubic feet (“MMcf”). Gas is converted to barrels of oil equivalents (“MBoe”) using a ratio of six Mcf of gas per Bbl of oil. 2018 2017 Oil Gas BOE Oil Gas BOE Proved reserves: Beginning of year 138 103 155 142 115 161 Revisions (33 ) (91 ) (48 ) (2 ) (4 ) (3 ) Extensions and discoveries - - - - - - Purchases of minerals-in-place 94 4,617 864 - - - Sales of minerals-in-place - - - - - - Production (2 ) (20 ) (5 ) (2 ) (8 ) (3 ) End of year 197 4,609 966 138 103 155 Proved developed reserves: Beginning of year 12 38 18 12 38 18 End of year 59 861 203 8 26 12 Proved not producing reserves: Beginning of year 54 14 57 54 14 57 End of year 138 3,747 763 54 14 56 Proved undeveloped reserves: Beginning of year 76 64 86 76 63 86 End of year - - - 76 63 87 |
Schedule of Estimated Present Value of Future Cash Flows Relating to Prove Reserves | . The prices used for each commodity for the years ended February 28, 2018 and 2017 as adjusted, were as follows: Oil (Bbl) Using NYMEX WTI Gas (Mcf) Using NYMEX Henry Hub 2018 (average price) $ 53.49 $ 3.00 2017 (average price) $ 43.05 $ 1.55 |
Schedule of Discounted Future Net Cash Flows Relating to Proven Reserves | The following table sets forth the standardized measure of discounted future net cash flows relating to proven reserves for the years ended February 28, 2018 and 2017 respectively (stated in thousands): 2018 2017 Future cash inflows $ 24,391 $ 6,113 Future costs: Production costs (4,530 ) (718 ) Future tax expense (2,209 ) (439 ) Future development costs (950 ) (1,093 ) Future net cash flows 16,702 3,863 10% annual discount for estimated timing of cash flows (8,755 ) (1,319 ) Standardized measure of discounted net cash flows $ 7,947 $ 2,544 |
Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows | The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows at 10% per annum for the years ended February 28, 2018 and 2017, respectively (stated in thousands): 2018 2017 Increase (decrease): Beginning of year $ 2,544 $ 2,369 Sales of oil produced, net of production costs 1,595 59 Net changes in sales and transfer prices and in production costs and production costs related to future production (10,443 ) 5,103 Previously estimated development costs incurred during the period - - Changes in future development costs 950 1,093 Revisions of previous quantity estimates due to prices and performance (649 ) (140 ) Accretion of discount 254 237 Discoveries, net of future production and development costs associated with these extensions and discoveries - - Purchases and sales of minerals in place 6,894 - Timing and other 6,802 (6,177 ) End of year $ 7,947 $ 2,544 |
Organization, Nature of Opera24
Organization, Nature of Operations and Summary of Significant Accounting Policies (Details Narrative) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items] | ||
Cash flow hedge, discount | 10.00% | |
Potentially dilutive securities outstanding | 1,440,000 | 0 |
Cash balances were uninsured | $ 0 | |
Minimum [Member] | ||
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items] | ||
Fixed assets estimated useful lives | 3 years | |
Maximum [Member] | ||
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items] | ||
Fixed assets estimated useful lives | 10 years |
Oil and Gas Properties (Details
Oil and Gas Properties (Details Narrative) | Dec. 28, 2017USD ($)aInteger | Dec. 06, 2016USD ($)a | Feb. 28, 2018USD ($) | Feb. 28, 2017USD ($) |
Accumulated depletion | $ 13,420 | $ 22,461 | ||
Deposit made on purchase of oil & gas properties | $ 1,600,000 | |||
King County Properties [Member] | 3D Seismic [Member] | ||||
Area of land, Lease | a | 340 | |||
King County Properties [Member] | Ratliff [Member] | ||||
Area of land, Lease | a | 640 | |||
King County Properties [Member] | ||||
Deposit made on purchase of oil & gas properties | $ 100,000 | |||
Acquisition interest rate, description | This acquisition represented a 100% working interest, with a 70% net revenue interest on such leasehold acreages. | |||
Jack County and Palo Pinto County Properties [Member] | ||||
Deposit made on purchase of oil & gas properties | $ 1,600,000 | |||
Area of land, Lease | a | 2,790.9 | |||
Number of oil and gas lease | Integer | 11 |
Oil and Gas Properties - Summar
Oil and Gas Properties - Summary of Oil and Gas Activities (Details) - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 | Feb. 28, 2016 |
Oil and gas properties, subject to amortization | $ 2,646,878 | $ 946,878 | $ 996,954 |
Asset retirement costs | 69,224 | 8,438 | 8,438 |
Accumulated depletion | (69,760) | (56,340) | (34,279) |
Total oil and gas assets | $ 2,646,342 | 898,976 | 971,113 |
Additions [Member] | |||
Oil and gas properties, subject to amortization | 1,700,000 | ||
Asset retirement costs | 60,786 | ||
Accumulated depletion | (13,420) | (22,461) | |
Total oil and gas assets | 1,747,366 | (22,461) | |
Sales [Member] | |||
Oil and gas properties, subject to amortization | (50,076) | ||
Asset retirement costs | |||
Accumulated depletion | 400 | ||
Total oil and gas assets | $ (49,676) | ||
Reclassifications [Member] | |||
Oil and gas properties, subject to amortization | |||
Asset retirement costs | |||
Accumulated depletion | |||
Total oil and gas assets |
Oil and Gas Properties - Schedu
Oil and Gas Properties - Schedule of Purchase Price and its Allocation to Net Assets Acquired (Details) | 12 Months Ended |
Feb. 28, 2018USD ($) | |
King County Properties [Member] | |
Cash paid | $ 100,000 |
Oil and gas properties | 105,642 |
Asset retirement obligation | (5,642) |
Total purchase price | 100,000 |
Jack County and Palo Pinto County Properties [Member] | |
Cash paid | 1,600,000 |
Oil and gas properties | 1,624,063 |
Asset retirement obligation | (24,063) |
Total purchase price | $ 1,600,000 |
Equipment (Details Narrative)
Equipment (Details Narrative) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Depreciation expense | $ 4,900 | $ 4,940 |
Used Vehicle [Member] | ||
Fixed assets estimated useful life | 5 years |
Equipment - Schedule of Fixed A
Equipment - Schedule of Fixed Assets (Details) - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 |
Property, Plant and Equipment [Abstract] | ||
Vehicle | $ 24,500 | $ 24,500 |
Less Accumulated depreciation | (11,854) | (6,954) |
Total | $ 12,646 | $ 17,546 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details Narrative) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Accretion expense | $ 5,826 | $ 912 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Asset Retirement Obligation (Details) | 12 Months Ended |
Feb. 28, 2018USD ($) | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations as of February 28, 2017 | $ 10,045 |
Additions | 29,705 |
Current revision of previous estimates | 31,081 |
Accretion during the year ended February 28, 2018 | 5,826 |
Asset retirement obligations as of February 28, 2018 | $ 76,657 |
Related Party Transactions (Det
Related Party Transactions (Details Narrative) - USD ($) | Feb. 21, 2018 | Dec. 28, 2017 | Aug. 02, 2017 | Jul. 27, 2017 | Apr. 07, 2017 | Feb. 28, 2018 | Feb. 28, 2017 |
Proceed from loan payable | $ 2,300,000 | $ 50,000 | |||||
Debt instrument principal amount | $ 1,550,000 | ||||||
Common stock, shares authorized | 150,000,000 | 150,000,000 | |||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |||||
Interest expense | $ 23,648 | $ 1,000 | |||||
International Western Oil Corporation [Member] | |||||||
Accounts payable and accrued expenses | $ 379,428 | ||||||
Series A Convertible Preferred Stock [Member] | |||||||
Number of common stock issued | |||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |||||
JBB Partners, Inc. [Member] | |||||||
Proceed from loan payable | $ 750,000 | ||||||
Debt instrument principal amount | 1,550,000 | ||||||
Common stock, shares authorized | 150,000,000 | ||||||
Preferred stock, shares authorized | 20,000,000 | ||||||
Accrued interest outstanding | $ 750,000 | ||||||
Interest expense | 12,513 | ||||||
JBB Partners, Inc. [Member] | Series A Convertible Preferred Stock [Member] | |||||||
Proceed from loan payable | $ 750,000 | ||||||
Debt conversion price per share | $ 0.02 | ||||||
Debt conversion of price, shares | 666,666.66 | 1,000,000 | |||||
Preferred stock, shares authorized | 1,000,000 | ||||||
Secured Promissory Note [Member] | JBB Partners, Inc. [Member] | |||||||
Proceed from loan payable | $ 200,000 | ||||||
Number of common stock issued | 17,920,000 | ||||||
Loan bears interest rate | 3.00% | ||||||
Loan maturity date | Jul. 27, 2018 | Apr. 7, 2018 | |||||
Debt instrument principal amount | $ 750,000 | ||||||
Promissory Note [Member] | JBB Partners, Inc. [Member] | |||||||
Proceed from loan payable | $ 1,550,000 | ||||||
Loan bears interest rate | 3.00% | ||||||
Loan maturity date | Dec. 28, 2018 | ||||||
Debt conversion price per share | $ 0.20 | ||||||
Interest expense | $ 7,899 | ||||||
Extended maturity date | Sep. 30, 2019 |
Settlement of Debt (Details Nar
Settlement of Debt (Details Narrative) - USD ($) | Aug. 02, 2017 | May 30, 2017 | Feb. 28, 2018 | Feb. 28, 2017 |
Related party payables | $ 159,260 | |||
Loss on extinguishment of debt | $ 1,228,322 | |||
Riggs Capital, Inc. [Member] | ||||
Related party payables | $ 379,428 | |||
Debt conversion of price, value | $ 379,428 | |||
Debt conversion of price, shares | 5,900,000 |
Income Taxes (Details Narrative
Income Taxes (Details Narrative) - USD ($) | Dec. 22, 2017 | Feb. 28, 2018 | Feb. 28, 2017 |
Provisions for income taxes | |||
Income tax of federal statutory rate | 21.00% | 32.70% | 34.00% |
Valuation allowance increase amount | $ 243,412 | $ 243,412 | |
Interest expense penalties | 1,000 | $ 0 | |
Net operating loss carryforwards | $ 1,441,033 | ||
Operating loss carryforwards expire date | 2,038 | ||
Percentage of ownership change of outstanding stock | 50.00% | ||
Income tax description | The Act makes broad and complex changes to the U.S. tax code, including but not limited to, reducing the U.S. federal corporate rate from 35% to 21%, allowing full expensing of qualified property acquired and placed in service after September 27, 2017 and imposing new limits on the deduction of net operating losses, executive compensation and net interest expense. | ||
Reduction in deferred tax asset | $ 360,842 | ||
Pre-ownership [Member] | |||
Net operating loss carryforwards | $ 1,100,000 |
Income Taxes - Schedule of Effe
Income Taxes - Schedule of Effective Income Tax Expense Reconciliation (Details) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Income Tax Disclosure [Abstract] | ||
Pretax book income | $ (833,505) | $ (594,802) |
Stock-based compensation | 78,995 | 72,579 |
Loss on settlement of debt | 200,831 | |
Change in valuation allowance | 243,412 | 629,562 |
Change in the effective rates | 331,363 | |
Other adjustments | (21,096) | (107,339) |
Total tax expense |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Tax Assets (Details) - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 |
Income Tax Disclosure [Abstract] | ||
Net operating losses carry forwards | $ 1,444,810 | $ 1,204,194 |
Difference in depletion, depreciation and capitalization method | (3,777) | (6,573) |
Total deferred tax assets | 1,441,033 | 1,197,621 |
Less valuation allowance | (1,441,033) | (1,197,621) |
Total deferred tax assets |
Commitments and Contingencies (
Commitments and Contingencies (Details Narrative) | 12 Months Ended | |
Feb. 28, 2018USD ($)a | Mar. 31, 2015USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | ||
Obligation lease extension amount | $ 13,400 | |
Rent expense | $ 37,588 | |
Area of land | a | 640 | |
Lease expire description | In the King County, Texas lease acreage, 640 acres are due to expire in June 2021 |
Equity Transactions (Details Na
Equity Transactions (Details Narrative) - USD ($) | Feb. 21, 2018 | Aug. 02, 2017 | Feb. 28, 2018 | Feb. 28, 2017 |
Common stock, shares authorized | 150,000,000 | 150,000,000 | ||
Common stock, designated | 150,000,000 | |||
Common stock, par value | $ 0.0001 | $ 0.001 | $ 0.001 | |
Preferred stock, designated | 20,000,000 | |||
Preferred stock, par value | $ 0.0001 | $ 0.001 | $ 0.001 | |
Proceed from loan payable | $ 2,300,000 | $ 50,000 | ||
Preferred stock, shares issued | ||||
Preferred stock, shares outstanding | ||||
Net cash proceeds of common stock | $ 365,000 | $ 1,001,200 | ||
Loss on extinguishment of debt | $ 1,228,322 | |||
Options to purchase common stock shares | 1,440,000 | 0 | ||
Stock option exercise price per share | $ 0.01 | |||
Stock option term | 2 years | |||
Options vesting period | 2 years | |||
Fair value of stock option granted | $ 431,956 | |||
Discount rate | 1.34% | |||
Expected life of years | 2 years | |||
Expected volatility | 482.51% | |||
Expected dividend | 0.00% | |||
Stock option intrinsic value | $ 417,600 | |||
Stock option expense | 126,000 | |||
Unrecognized compensation expense | $ 306,000 | |||
Stock option remaining life term | 1 year 5 months 5 days | |||
Mr. Patrick Norris [Member] | ||||
Number of common stock shares sold during period | 500,000 | |||
JBB Partners, Inc. [Member] | ||||
Common stock, shares authorized | 150,000,000 | |||
Proceed from loan payable | $ 750,000 | |||
JBB Partners, Inc. [Member] | Ross Henry Ramsey [Member] | ||||
Number of common stock shares sold during period | 17,920,000 | |||
JBB Partners, Inc. [Member] | Benjamin Tran [Member] | ||||
Number of common stock shares sold during period | 12,000,000 | |||
Riggs Capital, Inc. [Member] | Debt Conversion Agreement [Member] | ||||
Debt conversion of price, shares | 5,900,000 | |||
Debt conversion of price, value | $ 379,428 | |||
Series A Convertible Preferred Stock [Member] | ||||
Preferred stock, par value | $ 0.001 | $ 0.001 | ||
Stock issued during period of issuance of stock | ||||
Preferred stock, shares issued | 1,000,000 | 0 | ||
Preferred stock, shares outstanding | 1,000,000 | 0 | ||
Series A Convertible Preferred Stock [Member] | JBB Partners, Inc. [Member] | ||||
Proceed from loan payable | $ 750,000 | |||
Shares issued, price per share | $ 0.75 | |||
Debt conversion of price per share | $ 0.02 | |||
Debt conversion of price, shares | 666,666.66 | 1,000,000 | ||
Common Stock [Member] | ||||
Stock issued during period of issuance of stock | 34,520,000 | 3,518,949 | ||
Number of common stock shares sold during period | 34,520,000 | 3,518,948 | ||
Net cash proceeds of common stock | $ 365,000 | $ 1,001,200 | ||
Number of common stock issued for service | 315,000 | 862,100 | ||
Common stock issued for services | $ 483,152 | $ 426,934 | ||
Number of common stock issued to settlement of stock payable, shares | 12,000 | |||
Number of common stock issued to settlement of stock payable, value | $ 12,000 | |||
Minimum [Member] | ||||
Common stock, shares authorized | 90,000,000 | |||
Maximum [Member] | ||||
Common stock, shares authorized | 170,000,000 | |||
Maximum [Member] | Preferred Stock [Member] | ||||
Stock issued during period of issuance of stock | 20,000,000 |
Subsequent Events (Details Narr
Subsequent Events (Details Narrtive) - USD ($) | Jun. 26, 2018 | Feb. 28, 2018 |
Maximum loan amount | $ 1,550,000 | |
Subsequent Event [Member] | ||
Maximum loan amount | $ 1,000,000 | |
Advance amount | $ 100,000 | |
Stock conversion price per share | $ 0.20 | |
Debt maturity date description | The maturity date of the original amount and all the advances is September 30, 2019. |
Supplemental Oil and Gas Disc40
Supplemental Oil and Gas Disclosures (Unaudited) (Details Narrative) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Extractive Industries [Abstract] | ||
Unevaluated costs | $ 0 | $ 0 |
Standardized measure of discounted future estimated net cash flows rate | 10.00% | 10.00% |
Supplemental Oil and Gas Disc41
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 | Feb. 28, 2016 |
Extractive Industries [Abstract] | |||
Proved oil and gas properties | $ 2,716,102 | $ 955,316 | |
Unproved oil and gas properties | |||
Accumulated depreciation, depletion and amortization | (69,760) | (56,340) | $ (34,279) |
Total acquisition, development and exploration costs | $ 2,646,342 | $ 898,976 |
Supplemental Oil and Gas Disc42
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities (Details) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Extractive Industries [Abstract] | ||
Acquisition of properties - proved | $ 1,605,000 | $ 381,067 |
Acquisition of properties - unproved | ||
Exploration costs | 88,000 | |
Development costs | 536,325 | |
Disposition/sale | (5,000) | (50,076) |
Total costs incurred | $ 1,600,000 | $ 955,316 |
Supplemental Oil and Gas Disc43
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Quantities of Proved Oil and Gas Reserves (Details) | 12 Months Ended | |
Feb. 28, 2018MBblsMcfbbl | Feb. 28, 2017MBblsMcfbbl | |
Oil [Member] | ||
Proved reserves: Beginning of year | MBbls | 138,000 | 142,000 |
Proved reserves: Revisions | MBbls | (33,000) | (2,000) |
Proved reserves: Extensions and discoveries | MBbls | ||
Proved reserves: Purchases of minerals-in-place | MBbls | 94,000 | |
Proved reserves: Sales of minerals-in-place | MBbls | ||
Proved reserves: Production | MBbls | (2,000) | (2,000) |
Proved reserves: End of year | MBbls | 197,000 | 138,000 |
Proved developed reserves: Beginning of year | MBbls | 12,000 | 12,000 |
Proved developed reserves: End of year | MBbls | 59,000 | 12,000 |
Proved behind pipe reserves: Beginning of year | MBbls | 54,000 | 54,000 |
Proved behind pipe reserves: End of year | MBbls | 138,000 | 54,000 |
Proved undeveloped reserves: Beginning of year | MBbls | 76,000 | 76,000 |
Proved undeveloped reserves: End of year | MBbls | 76,000 | |
Gas [Member] | ||
Proved reserves: Beginning of year | Mcf | 103,000,000 | 115,000,000 |
Proved reserves: Revisions | Mcf | (91,000,000) | (4,000,000) |
Proved reserves: Extensions and discoveries | Mcf | ||
Proved reserves: Purchases of minerals-in-place | Mcf | 4,617,000,000 | |
Proved reserves: Sales of minerals-in-place | Mcf | ||
Proved reserves: Production | Mcf | (20,000,000) | (8,000,000) |
Proved reserves: End of year | Mcf | 4,609,000,000 | 103,000,000 |
Proved developed reserves: Beginning of year | Mcf | 38,000,000 | 38,000,000 |
Proved developed reserves: End of year | Mcf | 861,000,000 | 38,000,000 |
Proved behind pipe reserves: Beginning of year | Mcf | 14,000,000 | 14,000,000 |
Proved behind pipe reserves: End of year | Mcf | 3,747,000,000 | 14,000,000 |
Proved undeveloped reserves: Beginning of year | Mcf | 64,000,000 | 63,000,000 |
Proved undeveloped reserves: End of year | Mcf | 63,000,000 | |
BOE [Member] | ||
Proved reserves: Beginning of year | bbl | 155,000,000 | 161,000,000 |
Proved reserves: Revisions | bbl | (48,000,000) | (3,000,000) |
Proved reserves: Extensions and discoveries | bbl | ||
Proved reserves: Purchases of minerals-in-place | bbl | 864,000,000 | |
Proved reserves: Sales of minerals-in-place | bbl | ||
Proved reserves: Production | bbl | (5,000,000) | (3,000,000) |
Proved reserves: End of year | bbl | 966,000,000 | 155,000,000 |
Proved developed reserves: Beginning of year | bbl | 18,000,000 | 18,000,000 |
Proved developed reserves: End of year | bbl | 203,000,000 | 18,000,000 |
Proved behind pipe reserves: Beginning of year | bbl | 57,000,000 | 57,000,000 |
Proved behind pipe reserves: End of year | bbl | 763,000,000 | 57,000,000 |
Proved undeveloped reserves: Beginning of year | bbl | 86,000,000 | 86,000,000 |
Proved undeveloped reserves: End of year | bbl | 87,000,000 |
Supplemental Oil and Gas Disc44
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Present Value of Future Cash Flows Relating to Prove Reserves (Details) | 12 Months Ended | |
Feb. 28, 2018MBblsMcf | Feb. 28, 2017MBblsMcf | |
Oil (Bbl) Using NYMEX WTI [Member] | ||
Average price | MBbls | 53.49 | 43.05 |
Gas (Mcf) Using NYMEX Henry Hub [Member] | ||
Average price | Mcf | 3 | 1.55 |
Supplemental Oil and Gas Disc45
Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Discounted Future Net Cash Flows Relating to Proven Reserves (Details) - USD ($) | Feb. 28, 2018 | Feb. 28, 2017 | Feb. 29, 2016 |
Extractive Industries [Abstract] | |||
Future cash inflows | $ 24,391,000 | $ 6,113,000 | |
Production costs | (4,530,000) | (718,000) | |
Future tax expense | (2,209,000) | (439,000) | |
Future development costs | (950,000) | (1,093,000) | |
Future net cash flows | 16,702,000 | 3,863,000 | |
10% annual discount for estimated timing of cash flows | (8,755,000) | (1,319,000) | |
Standardized measure of discounted net cash flows | $ 7,947,000 | $ 2,544,000 | $ 2,369,000 |
Supplemental Oil and Gas Disc46
Supplemental Oil and Gas Disclosures - Schedule of Discounted Future Net Cash Flows Relating to Proven Reserves (Details) (Parenthetical) | Feb. 28, 2018 | Feb. 28, 2017 |
Extractive Industries [Abstract] | ||
Percentage of discount | 10.00% | 10.00% |
Supplemental Oil and Gas Disc47
Supplemental Oil and Gas Disclosures (Unaudited) - Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) | 12 Months Ended | |
Feb. 28, 2018 | Feb. 28, 2017 | |
Extractive Industries [Abstract] | ||
Beginning of year | $ 2,544,000 | $ 2,369,000 |
Sales of oil produced, net of production costs | 1,595,000 | 59,000 |
Net changes in sales and transfer prices and in production costs and production costs related to future production | (10,443,000) | 5,103,000 |
Previously estimated development costs incurred during the period | ||
Changes in future development costs | 950,000 | 1,093,000 |
Revisions of previous quantity estimates due to prices and performance | (649,000) | (140,000) |
Accretion of discount | 254,000 | 237,000 |
Discoveries, net of future production and development costs associated with these extensions and discoveries | ||
Purchases and sales of minerals in place | 6,894,000 | |
Timing and other | 6,802,000 | (6,177,000) |
End of year | $ 7,947,000 | $ 2,544,000 |