Norris Industries (NRIS) 10-K 1 Jun 17 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Feb. 28, 2017	Jun. 01, 2017	Aug. 31, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	INTERNATIONAL WESTERN PETROLEUM, INC.
Entity Central Index Key	1,603,793
Document Type	10-K
Document Period End Date	Feb. 28, 2017
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		48,811,013
Trading Symbol	INWP
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,017

Balance Sheets

Balance Sheets - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Current Assets
Cash and cash equivalents	$ 76,365	$ 542,228
Account receivable - oil & gas	8,170
Deposit on purchase of oil & gas properties	105,000
Total Current Assets	189,535	542,228
Oil and Gas Property - Full Cost Method
Properties subject to amortization	955,316	1,005,392
Less: accumulated depletion	(56,340)	(34,279)
Total Oil and Gas Property, net	898,976	971,113
Equipment, net	17,546	22,486
Total Assets	1,106,057	1,535,827
Current Liabilities
Accounts payable and accrued expenses	1,000	13,138
Account payable and accrued expenses - related parties	379,428	538,688
Loan payable	50,000
Stock payable	12,000
Total Current Liabilities	442,428	551,826
Asset Retirement Obligations	10,045	9,133
Total Liabilities	452,473	560,959
Stockholders' Equity
Preferred stock, $.001 par value per share 10,000,000 shares authorized; 0 shares issued and outstanding
Common stock, $0.001 par value per share, 90,000,000 shares authorized; 48,696,013 and 44,314,964 shares issued and outstanding on February 28, 2017 and February 29, 2016, respectively.	48,696	44,315
Additional paid-in capital	2,791,328	1,367,575
Accumulated deficit	(2,186,440)	(437,022)
Total Stockholder's Equity	653,584	974,868
Total Liabilities and Stockholders' Equity	$ 1,106,057	$ 1,535,827

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - $ / shares	Feb. 28, 2017	Feb. 29, 2016
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred Stock, shares authorized	10,000,000	10,000,000
Preferred Stock, shares issued	0	0
Preferred Stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	90,000,000	90,000,000
Common stock, shares issued	48,696,013	44,314,964
Common stock, shares outstanding	48,696,013	44,314,964

Statement of Operations

Statement of Operations - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Revenues
Oil and gas sales	$ 104,351	$ 172,890
Service income	45,000
Total Revenues	149,351	172,890
Operating Expenses
Lease operating expenses	158,150	44,562
Professional fees	1,299,306	249,315
General and administrative expenses	407,264	142,186
Depletion and accretion	23,373	36,988
Total Operating Expenses	1,888,093	473,051
Loss from Operations	(1,738,742)	(300,161)
Other Income (Expenses)
Gain on sale of property	20,324
Loss on investment	(30,000)
Interest expense	(1,000)
Total Other Expense	(10,676)
Net Loss	$ (1,749,418)	$ (300,161)
Net loss per common share -basic and diluted	$ (0.04)	$ (0.01)
Weighted average number of common shares outstanding - basic and diluted	46,416,182	44,131,230

Statement of Changes in Stockho

Statement of Changes in Stockholders' Equity - USD ($)	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]	Total
Balance, beginning at Feb. 28, 2015	$ 43,555	$ 215,235	$ (136,861)	$ 121,929
Balance shares, beginning at Feb. 28, 2015	43,554,964
Common stock issued for cash	$ 260	194,740		195,000
Common stock issued for cash, shares	260,000
Common stock issued for acquisition of oil and gas properties	$ 500	374,500		375,000
Common stock issued for acquisition of oil and gas properties, shares	500,000
Contributed capital		583,100		583,100
Common stock issued for consulting
Common stock issued for consulting, shares
Net loss			(300,161)	(300,161)
Balance, ending at Feb. 29, 2016	$ 44,315	1,367,575	(437,022)	974,868
Balance shares, ending 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	3,518,948
Common stock issued for acquisition of oil and gas properties
Common stock issued for acquisition of oil and gas properties, shares
Contributed capital
Common stock issued for consulting	$ 862	426,072		426,934
Common stock issued for consulting, shares	862,100
Net loss			(1,749,418)	(1,749,418)
Balance, ending at Feb. 28, 2017	$ 48,696	$ 2,791,328	$ (2,186,440)	$ 653,584
Balance shares, ending at Feb. 28, 2017	48,696,013

Statements of Cash Flows

Statements of Cash Flows - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Cash Flow from Operating Activities
Net loss	$ (1,749,418)	$ (300,161)
Adjustments to reconcile net loss to net cash from operating activities:
Depletion and accretion	23,373	36,988
Depreciation and amortization	4,940
Common stock issued for services	426,934
Gain on sale of oil & gas property	(20,324)
Loss on investment	30,000
Changes in operating assets and liabilities:
Accounts receivable - oil & gas	(8,170)
Accounts payable and accrued expenses	(12,138)	8,354
Accounts payable and accrued expenses - related parties		1,664
Net Cash used in Operating Activities	(1,304,803)	(253,155)
Cash Flow from Investing Activities
Deposit on purchase of oil and gas properties	(135,000)
Sale of oil & gas properties	70,000
Purchase of equipment		(24,500)
Net Cash used in Investing Activities	(65,000)	(24,500)
Cash Flow from Financing Activities
Proceed from loan payable	50,000
Payments on related party advances	(159,260)
Common stock issued for cash	1,001,200	195,000
Capital contribution		583,100
Proceeds from issuance of stock payable	12,000
Net Cash provided by Financing Activities	903,940	778,100
Net Decrease in Cash and Cash Equivalents	(465,863)	500,445
Cash and Cash Equivalents - beginning of year	542,228	41,783
Cash and Cash Equivalents - end of year	76,365	542,228
Supplemental Cash Flow Information
Cash paid for income taxes
Cash paid for interest
Noncash Investing and Financing Activities
Accrued oil and gas development cost payable to related party		533,954
Common stock issued for acquisition of oil and gas properties		375,000
Reclassification of pre-acquisition costs to oil and gas properties		88,000
Asset retirement obligation from acquisition of oil and gas properties		6,067
Asset retirement obligation - change in estimate		$ 2,371

Organization, Nature of Operati

Organization, Nature of Operations and Summary of Significant Accounting Policies	12 Months Ended
	Feb. 28, 2017
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 The accompanying financial statements of International Western Petroleum, Inc. (“IWP” or 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”). International Western Petroleum, Inc. (“IWP” or the “Company”) 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 located in the Ellenberger formation in Coleman County, Texas. 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 . 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, 2017, $0 of the Company’s cash balances was uninsured. The Company has not experienced any losses on such accounts. Sales to one customer comprised 100% of the Company’s total oil and gas revenues for the year ended February 28, 2017. The Company believes that, in the event that its primary customer is unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices. 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. 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. 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. Net Loss per Common Share Basic net loss per common share amounts are computed by dividing the net loss available to International Western Petroleum, 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, 2017 and February29, 2016, there were no potentially dilutive securities outstanding. Recent Accounting Pronouncements There were various accounting standards and interpretations issued during 2017 and 2016, none of which are expected to have a material impact on the Company’s financial position, operations or cash flows. In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company is currently evaluating the impact of its pending adoption of ASU 2014-09 on its consolidated financial statements and have not yet determined the method by which the Company will adopt the standard in 2017. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard requires management to assess the Company’s ability to continue as a going concern. Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements. The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016. We do not expect the adoption of this pronouncement to have a material impact on our financial statements. Subsequent Events The Company has evaluated all transactions through the date the financial statements were issued for subsequent event disclosure consideration. In March 2017, the Company issued 115,000 shares of the common stock of the Company for consulting services related to accounting and social media services. On April 7, 2017 (the “ Effective Date Secured Promissory Note JBB Loan On May 30, 2017, the Company’s affiliate, International Western Oil Corporation (IWO) sold its affiliate debt of $379,428 to Riggs Capital, Inc.

Going Concern

Going Concern	12 Months Ended
	Feb. 28, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Going Concern	Note 2 – Going Concern The Company remains dependent upon funding from non-operating sources, principally related parties. The Company’s financial statements have been presented on the basis that is a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company generated a net loss of $1,749,418 and used $1,304,803 of cash in operations during the year ended February 28, 2017. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of these uncertainties. There are no assurances that the Company will be able to either (1) achieve a level of revenues adequate to generate sufficient cash flow from operations; or (2) obtain additional financing through either private placement, public offerings and/or bank financing necessary to support the Company’s working capital requirements. To the extent that funds generated from operations and any private placements, public offerings and/or bank financing are insufficient, the Company will have to raise additional working capital. No assurance can be given that additional financing will be available, or if available, will be on terms acceptable to the Company. If adequate working capital is not available, the Company may be required to curtail or cease its operations. Management believes that actions presently being taken to obtain additional funding and implement its strategic plans provide the opportunity for the Company to continue as a going concern.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Feb. 28, 2017
Extractive Industries [Abstract]
Oil and Gas Properties	Note 3 – Oil and Gas Properties The following table summarizes the Company’s oil and gas activities by classification for the years ended February 29, 2016 and February 28, 2017: February 28, 2015 Additions Reclass (1) February 29, 2016 Oil and gas properties, subject to depletion $ - $ 908,954 $ 88,000 $ 996,954 Asset retirement costs - 8,438 - 8,438 Accumulated depletion - (34,279 ) - (34,279 ) Total oil and gas assets $ - $ 883,113 $ 88,000 $ 971,113 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 (1) The Company reclassified $88,000 of the pre-acquisition costs associated with the Bend Arch properties acquired to oil & gas properties subject to amortization. Accordingly, prior to February 28, 2015, the Company had no oil & gas properties. The depletion recorded for production on proved properties for the years ended February 28, 2017 and February 29, 2016, amounted to $22,061 and $34,279, respectively.

Equipment

Equipment	12 Months Ended
	Feb. 28, 2017
Property, Plant and Equipment [Abstract]
Equipment	Note 4 – Equipment The Company’s fixed assets consisted of a used vehicle and has a remaining estimated useful life of five years. Fixed asset consists of the following: February 28, 2017 February 29, 2016 Vehicle $ 24,500 $ 24,500 Accumulated depreciation (6,954 ) (2,014 ) Total $ 17,546 $ 22,486 The Company recorded depreciation expense of $4,940 and $2,014, respectively, during the years ended February 28, 2017 and February 29, 2016.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Feb. 28, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 5 – Asset Retirement Obligations The following table summarizes the change in the Company’s asset retirement obligations during the year ended February 28, 2017: Amount Asset retirement obligations as of February 29, 2016 $ 9,133 Additions Current year revision of previous estimates Accretion during the year ended February 28, 2017 912 Asset retirement obligations as of February 28, 2017 $ 10,045 During the years ended February 28, 2017 and February 29, 2016, the Company recognized accretion expense of $912 and $695, respectively.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Feb. 28, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 6 – Related Party Transactions During the year ended February 29, 2016, the Company received $583,100 of cash from IWO which the Company recorded as contributed capital. As of February 28, 2017 and February 29, 2016, the Company had outstanding accounts payable and accrued expenses – related parties of $379,428 and $538,688, respectively.

Loan Payable

Loan Payable	12 Months Ended
	Feb. 28, 2017
Debt Disclosure [Abstract]
Loan Payable	Note 7 – Loan Payable During the year ended February 28, 2017, the Company borrowed $50,000 from a shareholder of the Company for the purchase of the Propst Lease located in West Central Jones County of Texas. This loan payable is secured by 5% working interest of the Propst Lease, bears interest of $4,000 and is due on April 26, 2017.

Equity

Equity	12 Months Ended
	Feb. 28, 2017
Equity [Abstract]
Equity	Note 8 – Equity During the year ended February 29, 2016, the Company sold 260,000 shares of the Company’s common stock for net cash proceeds of $195,000, issued 500,000 shares of the Company’s common stock to a related party to acquire an oil and gas property, and received $583,100 of funds from a related party as contributed capital (see Note 6). During the year ended February 28, 2017, the Company sold 3,518,948 shares of the Company’s common stock for net cash proceeds of $1,001,200, issued 862,100 shares, valued at their fair value of $426,934, of the Company’s common stock for consulting services. For the shares sold for cash but not issued before February 28, 2017, the Company recorded a stock payable of $12,000 on its balance sheet.

Income Taxes

Income Taxes	12 Months Ended
	Feb. 28, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 9 – Income Taxes Due to the Company’s net losses, there were no provisions for income taxes for the years ended February 28, 2017 and February 29, 2016. 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 35% is principally due to the change in the valuation allowance. Deferred income tax assets for the years ended February 28, 2017 and February 29, 2016 are as follows: Deferred Tax Assets Year Ended February 28, 2017 Year Ended February 29, 2016 Net operating losses carry forwards $ 766,700 $ 122,045 Difference in depletion, depreciation and capitalization method - 15,133 Total deferred tax assets 766,700 137,138 Less valuation allowance (766,700 ) $ (137,138 ) 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, 2017 and February 29, 2016. The net change in the total valuation allowance from February 29, 2016 and February 28, 2017, was an increase of $629,562. 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, 2017 and February 29, 2016, the Company did not have any significant uncertain tax positions or unrecognized tax benefits. The Company incurred interest expense $1,000 and $0 penalties was recognized for the years ended February 28, 2017, and there were no interest or penalty for February 29, 2016. As of February 28, 2017, the Company has federal net operating loss carryforwards of approximately $2,186,440 for federal and state tax purposes, respectively, which if not utilized, will expire beginning in 2034, 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. Due to the impact of temporary and permanent differences between the book and tax calculations of net loss, the Company experiences an effective tax rate above the federal statutory rate of 35%.

Subsequent Events

Subsequent Events	12 Months Ended
	Feb. 28, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 10 – Subsequent Events In March 2017, the Company issued 115,000 shares of the common stock of the Company for consulting services related to accounting and social media services. On April 7, 2017, the Company entered into a secured promissory note (the “ Secured Promissory Note JBB Loan On May 30, 2017, the Company’s affiliate, International Western Oil Corporation (IWO) sold its affiliate debt of $379,428 to Riggs Capital, Inc.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Feb. 28, 2017
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 Ralph E. Davis, 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 our 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, 2017. 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, 2017 February 29, 2016 Proved oil and gas properties $ 955,316 $ 1,005,392 Unproved oil and gas properties - - Accumulated depreciation, depletion and amortization (56,340 ) (34,279 ) Total acquisition, development and exploration costs $ 898,976 $ 971,113 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities At February 28, 2017 and February 29, 2016, unevaluated costs of $0 were excluded from the depletion base. February 28, 2017 February 29, 2016 Acquisition of properties – proved $ 381,067 $ 381,067 Acquisition of properties – unproved - - Exploration costs 88,000 88,000 Development costs 536,325 536,325 Disposition/sale 50,076 - Total costs incurred $ 955,316 $ 1,005,392 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, 2017 and February 29, 2016. 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. 2017 2016 Oil Gas BOE Oil Gas BOE Proved reserves: Beginning of year 142 115 161 - - - Revisions - - - - - - Extensions and discoveries - - - - - - Purchases of minerals-in-place 137 103 155 146 128 167 Sales of minerals-in-place - - - - - - Production (2 ) (11 ) (4 ) (4 ) (13 ) (6 ) End of year 277 207 312 142 115 161 Proved developed reserves: Beginning of year 12 38 18 - - - End of year 12 38 18 12 38 18 Proved behind pipe reserves: Beginning of year 54 14 57 - - - End of year 54 14 57 54 14 57 Proved undeveloped reserves: Beginning of year 76 63 86 - - - End of year 76 63 86 76 63 86 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 2017 were computed by applying the average price for the year to the year-end quantities of proved reserves. The 2017 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, 2017 and February 29, 2016 as adjusted, were as follows: Oil (Bbl) Using NYMEX WTI Gas (Mcf) Using NYMEX Henry Hub 2017 (average price) $ 43.05 $ 1.55 2016 (average price) $ 47.31 $ 2.63 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, 2017 and February 29, 2016 respectively (stated in thousands): 2017 2016 Future cash inflows $ 6,114 $ 6102 Future costs: Production costs (718 ) (794 ) Future tax expense (286 ) (294 ) Future development costs (1,093 ) (1,112 ) Future net cash flows 4,017 3,901 10% annual discount for estimated timing of cash flows (1,473 ) (1,533 ) Standardized measure of discounted net cash flows $ 2,544 $ 2,369 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, 2017 and February 29, 2016, respectively (stated in thousands): 2017 2016 Increase (decrease): Beginning of year $ - $ - Sales of oil produced, net of production costs 77 406 Net changes in sales and transfer prices and in production costs and production costs related to future production - - Previously estimated development costs incurred during the period - - Changes in future development costs - - Revisions of previous quantity estimates due to prices and performance - - Accretion of discount - - Discoveries, net of future production and development costs associated with these extensions and discoveries - - Purchases and sales of minerals in place 2,467 1,963 Timing and other - - End of year

Organization, Nature of Opera18

Organization, Nature of Operations and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Feb. 28, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 .
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, 2017, $0 of the Company’s cash balances was uninsured. The Company has not experienced any losses on such accounts. Sales to one customer comprised 100% of the Company’s total oil and gas revenues for the year ended February 28, 2017. The Company believes that, in the event that its primary customer is unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.
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.
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.
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.
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 International Western Petroleum, 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, 2017 and February29, 2016, there were no potentially dilutive securities outstanding.
Recent Accounting Pronouncements	Recent Accounting Pronouncements There were various accounting standards and interpretations issued during 2017 and 2016, none of which are expected to have a material impact on the Company’s financial position, operations or cash flows. In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company is currently evaluating the impact of its pending adoption of ASU 2014-09 on its consolidated financial statements and have not yet determined the method by which the Company will adopt the standard in 2017. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard requires management to assess the Company’s ability to continue as a going concern. Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements. The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016. We do not expect the adoption of this pronouncement to have a material impact on our financial statements.
Subsequent Events	Subsequent Events The Company has evaluated all transactions through the date the financial statements were issued for subsequent event disclosure consideration. In March 2017, the Company issued 115,000 shares of the common stock of the Company for consulting services related to accounting and social media services. On April 7, 2017 (the “ Effective Date Secured Promissory Note JBB Loan On May 30, 2017, the Company’s affiliate, International Western Oil Corporation (IWO) sold its affiliate debt of $379,428 to Riggs Capital, Inc.

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Feb. 28, 2017
Extractive Industries [Abstract]
Summary of Oil and Gas Activities	The following table summarizes the Company’s oil and gas activities by classification for the years ended February 29, 2016 and February 28, 2017: February 28, 2015 Additions Reclass (1) February 29, 2016 Oil and gas properties, subject to depletion $ - $ 908,954 $ 88,000 $ 996,954 Asset retirement costs - 8,438 - 8,438 Accumulated depletion - (34,279 ) - (34,279 ) Total oil and gas assets $ - $ 883,113 $ 88,000 $ 971,113 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 (1) The Company reclassified $88,000 of the pre-acquisition costs associated with the Bend Arch properties acquired to oil & gas properties subject to amortization. Accordingly, prior to February 28, 2015, the Company had no oil & gas properties.

Equipment (Tables)

Equipment (Tables)	12 Months Ended
	Feb. 28, 2017
Property, Plant and Equipment [Abstract]
Schedule of Equipment	The Company’s fixed assets consisted of a used vehicle and has a remaining estimated useful life of five years. Fixed asset consists of the following: February 28, 2017 February 29, 2016 Vehicle $ 24,500 $ 24,500 Accumulated depreciation (6,954 ) (2,014 ) Total $ 17,546 $ 22,486

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Feb. 28, 2017
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, 2017: Amount Asset retirement obligations as of February 29, 2016 $ 9,133 Additions Current year revision of previous estimates Accretion during the year ended February 28, 2017 912 Asset retirement obligations as of February 28, 2017 $ 10,045

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Feb. 28, 2017
Income Tax Disclosure [Abstract]
Schedule of Deferred Income Tax Assets	Deferred income tax assets for the years ended February 28, 2017 and February 29, 2016 are as follows: Deferred Tax Assets Year Ended February 28, 2017 Year Ended February 29, 2016 Net operating losses carry forwards $ 766,700 $ 122,045 Difference in depletion, depreciation and capitalization method - 15,133 Total deferred tax assets 766,700 137,138 Less valuation allowance (766,700 ) $ (137,138 ) Total deferred tax assets $ - $ -

Supplemental Oil and Gas Disc23

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Feb. 28, 2017
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, 2017 February 29, 2016 Proved oil and gas properties $ 955,316 $ 1,005,392 Unproved oil and gas properties - - Accumulated depreciation, depletion and amortization (56,340 ) (34,279 ) Total acquisition, development and exploration costs $ 898,976 $ 971,113
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	February 28, 2017 February 29, 2016 Acquisition of properties – proved $ 381,067 $ 381,067 Acquisition of properties – unproved - - Exploration costs 88,000 88,000 Development costs 536,325 536,325 Disposition/sale 50,076 - Total costs incurred $ 955,316 $ 1,005,392
Schedule of Estimated Quantities of Proved Oil and Gas Reserves	reserves and proved undeveloped reserves for the years ended February 28, 2017 and February 29, 2016. 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. 2017 2016 Oil Gas BOE Oil Gas BOE Proved reserves: Beginning of year 142 115 161 - - - Revisions - - - - - - Extensions and discoveries - - - - - - Purchases of minerals-in-place 137 103 155 146 128 167 Sales of minerals-in-place - - - - - - Production (2 ) (11 ) (4 ) (4 ) (13 ) (6 ) End of year 277 207 312 142 115 161 Proved developed reserves: Beginning of year 12 38 18 - - - End of year 12 38 18 12 38 18 Proved behind pipe reserves: Beginning of year 54 14 57 - - - End of year 54 14 57 54 14 57 Proved undeveloped reserves: Beginning of year 76 63 86 - - - End of year 76 63 86 76 63 86
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, 2017 and February 29, 2016 as adjusted, were as follows: Oil (Bbl) Using NYMEX WTI Gas (Mcf) Using NYMEX Henry Hub 2017 (average price) $ 43.05 $ 1.55 2016 (average price) $ 47.31 $ 2.63
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, 2017 and February 29, 2016 respectively (stated in thousands): 2017 2016 Future cash inflows $ 6,114 $ 6102 Future costs: Production costs (718 ) (794 ) Future tax expense (286 ) (294 ) Future development costs (1,093 ) (1,112 ) Future net cash flows 4,017 3,901 10% annual discount for estimated timing of cash flows (1,473 ) (1,533 ) Standardized measure of discounted net cash flows $ 2,544 $ 2,369
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, 2017 and February 29, 2016, respectively (stated in thousands): 2017 2016 Increase (decrease): Beginning of year $ - $ - Sales of oil produced, net of production costs 77 406 Net changes in sales and transfer prices and in production costs and production costs related to future production - - Previously estimated development costs incurred during the period - - Changes in future development costs - - Revisions of previous quantity estimates due to prices and performance - - Accretion of discount - - Discoveries, net of future production and development costs associated with these extensions and discoveries - - Purchases and sales of minerals in place 2,467 1,963 Timing and other - - End of year $ 2,544 $ 2,369

Organization, Nature of Opera24

Organization, Nature of Operations and Summary of Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Cash balances were uninsured	$ 0
Cash flow hedge, discount	10.00%
Fixed Assets estimated useful lives	5 years
Loan interest rate	5.00%
Debt issued to affiliate	$ 379,428	$ 538,688
April 7, 2017 [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Debt maturity date	Apr. 7, 2018
April 7, 2017 [Member] | JBB Partners, Inc. [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Secured loan	$ 200,000
Loan interest rate	3.00%
May 30, 2017 [Member] | Riggs Capital, Inc [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Debt issued to affiliate	$ 379,428
Consultant [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Number of common stock issued for service	115,000
Ross Henry Ramsey [Member] | April 7, 2017 [Member] | JBB Partners, Inc. [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Number of common stock	17,920,000
Benjamin Tran [Member] | April 7, 2017 [Member] | JBB Partners, Inc. [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Number of common stock	12,000,000
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
One Customer [Member] | Oil And Gas Revenues [Member]
Organization Consolidation And Presentation Of Financial Statements Disclosure And Significant Accounting Policies [Line Items]
Concentration of risk percentage	100.00%

Going Concern (Details Narrativ

Going Concern (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net loss	$ 1,749,418	$ 300,161
Cash flows from operations	$ 1,304,803	$ 253,155

Oil and Gas Properties (Details

Oil and Gas Properties (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Extractive Industries [Abstract]
Accumulated depletion	$ 22,061	$ 34,279

Oil and Gas Properties - Summar

Oil and Gas Properties - Summary of Oil and Gas Activities (Details) - USD ($)		Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015
Oil and gas properties, subject to depletion		$ 946,878	$ 996,954
Asset retirement costs		8,438	8,438
Accumulated depletion		(56,340)	(34,279)
Total oil and gas assets		898,976	971,113
Additions [Member]
Oil and gas properties, subject to depletion			908,954
Asset retirement costs			8,438
Accumulated depletion		(22,461)	(34,279)
Total oil and gas assets		(22,461)	883,113
Reclass [Member]
Oil and gas properties, subject to depletion	[1]		88,000
Asset retirement costs	[1]
Accumulated depletion	[1]
Total oil and gas assets	[1]		$ 88,000
Sale [Member]
Oil and gas properties, subject to depletion		(50,076)
Asset retirement costs
Accumulated depletion		400
Total oil and gas assets		$ (49,676)
[1]	The Company reclassified $88,000 of the pre-acquisition costs associated with the Bend Arch properties acquired to oil & gas properties subject to amortization. Accordingly, prior to February 28, 2015, the Company had no oil & gas properties.

Oil and Gas Properties - Summ28

Oil and Gas Properties - Summary of Oil and Gas Activities (Details) (Parenthetical)	12 Months Ended
	Feb. 28, 2017USD ($)
Extractive Industries [Abstract]
Reclassification of pre-acquisition costs to oil and gas properties	$ 88,000

Equipment (Details Narrative)

Equipment (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Fixed assets estimated useful life	5 years
Depreciation expense	$ 4,940
Used Vehicle [Member]
Fixed assets estimated useful life	5 years

Equipment - Schedule of Equipme

Equipment - Schedule of Equipment (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Property, Plant and Equipment [Abstract]
Vehicle	$ 24,500	$ 24,500
Accumulated depreciation	(6,954)	(2,014)
Total	$ 17,546	$ 22,486

Asset Retirement Obligations (D

Asset Retirement Obligations (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 912	$ 695

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligation (Details)	12 Months Ended
	Feb. 28, 2017USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations as of February 29, 2016	$ 9,133
Additions
Current year revision of previous estimates
Accretion during the year ended February 28, 2017	912
Asset retirement obligations as of February 28, 2017	$ 10,045

Related Party Transactions (Det

Related Party Transactions (Details Narrative) - USD ($)	12 Months Ended
	Feb. 29, 2016	Feb. 28, 2017
Related Party Transactions [Abstract]
Company contributed capital	$ 583,100
Account payable and accrued expenses - related parties	$ 538,688	$ 379,428

Loan Payable (Details Narrative

Loan Payable (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Proceed from loan payable	$ 50,000
Percentage of working interest	5.00%
April 26, 2017 [Member]
Interest	$ 4,000

Equity (Details Narrative)

Equity (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Net cash proceeds of common stock	$ 12,000
Proceeds from contributed capital - related party		583,100
Common stock issued for services	426,934
Stock payable	$ 12,000
Common Stock [Member]
Number of common stock shares sold during period	3,518,948
Net cash proceeds of common stock	$ 1,001,200
Number of common stock issued for service	862,100
Common stock issued for services	$ 862
Related Party [Member]
Number of common stock shares sold during period		260,000
Net cash proceeds of common stock		$ 195,000
Common stock issued for acquisition of oil and gas properties, shares		500,000

Income Taxes (Details Narrative

Income Taxes (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
Income Tax Disclosure [Abstract]
Provisions for income taxes	$ 0	$ 0
Income tax of federal statutory rate	35.00%
Valuation allowance increase amount	$ 629,562	629,562
Interest expense penalties	1,000	$ 0
Net operating loss carryforwards	$ 2,186,440
Operating loss carryforwards expire date	2,034
Percentage of ownership change of outstanding stock	50.00%
Effective tax rate above federal statutory rate	35.00%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Income Tax Assets (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016
Income Tax Disclosure [Abstract]
Net operating losses carry forwards	$ 766,700	$ 122,045
Difference in depletion, depreciation and capitalization method		15,133
Total deferred tax assets	766,700	137,138
Less valuation allowance	(766,700)	(137,138)
Total deferred tax assets

Subsequent Events (Details Narr

Subsequent Events (Details Narrative) - USD ($)	Apr. 07, 2017	Mar. 31, 2017	Feb. 28, 2017	May 30, 2017	Feb. 29, 2016
Loan interest rate			5.00%
Debt issued to affiliate			$ 379,428		$ 538,688
Subsequent Event [Member]
Loan interest rate	3.00%
Debt maturity date	Apr. 7, 2018
Subsequent Event [Member] | Riggs Capital, Inc [Member]
Debt issued to affiliate				$ 379,428
Subsequent Event [Member] | JBB Partners, Inc. [Member] | Ross Henry Ramsey [Member]
Number of common stock	17,920,000
Subsequent Event [Member] | JBB Partners, Inc. [Member] | Benjamin Tran [Member]
Number of common stock	12,000,000
Subsequent Event [Member] | Consulting Service [Member]
Number of shares issued for consulting services		115,000	115,000

Supplemental Oil and Gas Disc39

Supplemental Oil and Gas Disclosures (Unaudited) (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016
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 Disc40

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015
Extractive Industries [Abstract]
Proved oil and gas properties	$ 955,316	$ 1,005,392
Unproved oil and gas properties
Accumulated depreciation, depletion and amortization	(56,340)	(34,279)
Total acquisition, development and exploration costs	$ 898,976	$ 971,113

Supplemental Oil and Gas Disc41

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, 2017	Feb. 28, 2016
Extractive Industries [Abstract]
Acquisition of properties - proved	$ 381,067	$ 381,067
Acquisition of properties - unproved
Exploration costs	88,000	88,000
Development costs	536,325	536,325
Disposition/sale	50,076
Total costs incurred	$ 955,316	$ 1,005,392

Supplemental Oil and Gas Disc42

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Quantities of Proved Oil and Gas Reserves (Details)	12 Months Ended
	Feb. 28, 2017bblMBblsMMcf	Feb. 29, 2016bblMBblsMMcf
Oil [Member]
Proved reserves: Beginning of year	142,000,000
Proved reserves: Revisions
Proved reserves: Extensions and discoveries
Proved reserves: Purchases of minerals-in-place	137,000,000	146,000,000
Proved reserves: Sales of minerals-in-place
Proved reserves: Production	(2,000,000)	(4,000,000)
Proved reserves: End of year	277,000,000	142,000,000
Proved developed reserves: Beginning of year	12,000,000
Proved developed reserves: End of year	12,000,000	12,000,000
Proved behind pipe reserves: Beginning of year	54,000,000
Proved behind pipe reserves: End of year	54,000,000	54,000,000
Proved undeveloped reserves: Beginning of year	76,000,000
Proved undeveloped reserves: End of year	76,000,000	76,000,000
Gas [Member]
Proved reserves: Beginning of year | MMcf	115,000,000
Proved reserves: Revisions | MMcf
Proved reserves: Extensions and discoveries | MMcf
Proved reserves: Purchases of minerals-in-place | MMcf	103,000,000	128,000,000
Proved reserves: Sales of minerals-in-place | MMcf
Proved reserves: Production | MMcf	(11,000,000)	(13,000,000)
Proved reserves: End of year | MMcf	207,000,000	115,000,000
Proved developed reserves: Beginning of year | MMcf	38,000,000
Proved developed reserves: End of year | MMcf	38,000,000	38,000,000
Proved behind pipe reserves: Beginning of year | MMcf	14,000,000
Proved behind pipe reserves: End of year | MMcf	14,000,000	14,000,000
Proved undeveloped reserves: Beginning of year	63,000,000
Proved undeveloped reserves: End of year	63,000,000	63,000,000
BOE [Member]
Proved reserves: Beginning of year | bbl	161,000,000
Proved reserves: Revisions | bbl
Proved reserves: Extensions and discoveries | bbl
Proved reserves: Purchases of minerals-in-place | bbl	155,000,000	167,000,000
Proved reserves: Sales of minerals-in-place | bbl
Proved reserves: Production | bbl	(4,000,000)	(6,000,000)
Proved reserves: End of year | bbl	312,000,000	161,000,000
Proved developed reserves: Beginning of year | bbl	18,000,000
Proved developed reserves: End of year | bbl	18,000,000	18,000,000
Proved behind pipe reserves: Beginning of year | bbl	57,000,000
Proved behind pipe reserves: End of year | bbl	57,000,000	57,000,000
Proved undeveloped reserves: Beginning of year	86,000,000
Proved undeveloped reserves: End of year	86,000,000	86,000,000

Supplemental Oil and Gas Disc43

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, 2017bblMMcf	Feb. 29, 2016bblMMcf
Oil (Bbl) Using NYMEX WTI [Member]
Average price | bbl	43.05	47.31
Gas (Mcf) Using NYMEX Henry Hub [Member]
Average price | MMcf	1.55	2.63

Supplemental Oil and Gas Disc44

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Discounted Future Net Cash Flows Relating to Proven Reserves (Details) - USD ($)	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2016	Feb. 28, 2015
Extractive Industries [Abstract]
Future cash inflows	$ 6,114,000	$ 6,102,000
Production costs	(718,000)	(794,000)
Future tax expense	(286,000)	(294,000)
Future development costs	(1,093,000)	(1,112,000)
Future net cash flows	4,017,000	3,901,000
10% annual discount for estimated timing of cash flows	(1,473,000)	(1,533,000)
Standardized measure of discounted net cash flows	$ 2,544,000	$ 2,369,000	$ 2,369,000

Supplemental Oil and Gas Disc45

Supplemental Oil and Gas Disclosures - Schedule of Discounted Future Net Cash Flows Relating to Proven Reserves (Details) (Parenthetical)	Feb. 28, 2017	Feb. 29, 2016
Extractive Industries [Abstract]
Percentage of discount	10.00%	10.00%

Supplemental Oil and Gas Disc46

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, 2017	Feb. 28, 2016
Extractive Industries [Abstract]
Beginning of year	$ 2,369,000
Sales of oil produced, net of production costs	77,000	406,000
Net changes in sales and transfer prices and in production costs and production costs related to future production
Previously estimated development costs incurred during the period
Changes in future development costs
Revisions of previous quantity estimates due to prices and performance
Accretion of discount
Discoveries, net of future production and development costs associated with these extensions and discoveries
Purchases and sales of minerals in place	2,467,000	1,963,000
Timing and other
End of year	$ 2,544,000	$ 2,369,000