Daybreak Oil and Gas (DBRM) 10-K 25 May 18 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Feb. 28, 2018	May 24, 2018	Aug. 31, 2017
Document And Entity Information
Entity Registrant Name	Daybreak Oil & Gas, Inc.
Entity Central Index Key	1,164,256
Document Type	10-K
Document Period End Date	Feb. 28, 2018
Amendment Flag	false
Current Fiscal Year End Date	--02-28
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 493,024
Entity Common Stock, Shares Outstanding		51,532,364
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 and cash equivalents	$ 48,535	$ 42,003
Accounts receivable:
Crude oil sales	104,840	83,405
Joint interest participants	58,452	55,154
Other receivables, net	0	4,489
Prepaid expenses and other current assets	21,796	24,197
Restricted short-term time deposit	100,029	100,060
Total current assets	333,652	309,308
CRUDE OIL AND NATURAL GAS PROPERTIES, successful efforts method, net
Proved properties	714,609	853,552
Unproved properties	31,187	59,375
PREPAID DRILLING COSTS	16,452	41,078
Total assets	1,095,900	1,263,313
CURRENT LIABILITIES:
Accounts payable and other accrued liabilities	2,022,672	1,727,955
Accounts payable - related parties	1,664,845	1,414,481
Accrued interest	1,822,673	446,232
Notes payable, related party	250,100	250,100
12% Notes payable, net of discount	307,571	0
12% Notes payable, related party, net of discount	244,103	0
Debt, current portion, net of deferred financing costs	9,157,794	8,805,846
Line of credit	873,350	817,622
Total current liabilities	16,343,108	13,462,236
LONG TERM LIABILITIES:
12% Notes payable, net of discount	0	299,465
12% Note payable - related party, net of discount	0	237,671
Asset retirement obligation	37,174	93,409
Total liabilities	16,380,282	14,092,781
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' DEFICIT:
Preferred stock	0	0
Common stock	51,532	51,487
Additional paid-in capital	22,997,759	22,997,789
Accumulated deficit	(38,334,383)	(35,879,469)
Total stockholders' deficit	(15,284,382)	(12,829,468)
Total liabilities and stockholders' deficit	1,095,900	1,263,313
Series A Convertible Preferred Stock
STOCKHOLDERS' DEFICIT:
Preferred stock	$ 710	$ 725

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Preferred stock, par value in dollars	$ 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 in dollars	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	51,532,364	51,487,373
Common stock, shares outstanding	51,532,364	51,487,373
Deferred financing costs	$ 0	$ 238,598
Unearned debt discount, current	7,429	0
Unearned debt discount, related party, current	5,897	0
Unearned debt discount, noncurrent	0	15,535
Unearned debt discount, related party, noncurrent	$ 0	$ 12,329
Series A Convertible Preferred Stock
Preferred stock, par value in dollars	$ 0.001	$ 0.001
Preferred stock, shares authorized	2,400,000	2,400,000
Preferred stock, shares issued	709,568	724,565
Preferred stock, shares outstanding	709,568	724,565
Preferred stock, cumulative dividend rate	6.00%	6.00%

Statements of Operations

Statements of Operations - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
REVENUE:
Crude oil sales	$ 628,652	$ 482,656
OPERATING EXPENSES:
Production	170,966	163,654
Exploration and drilling	107,884	9,297
Depreciation, depletion, and amortization	82,707	110,285
General and administrative	981,290	1,068,212
Total operating expenses	1,342,847	1,351,448
OPERATING LOSS	(714,195)	(868,792)
OTHER INCOME (EXPENSE):
Interest income	54	81
Interest expense	(1,740,773)	(2,994,466)
Total other expenses	(1,740,719)	(2,994,385)
LOSS FROM CONTINUING OPERATIONS	(2,454,914)	(3,863,177)
DISCONTINUED OPERATIONS
Income from discontinued operations	0	394,623
NET LOSS	(2,454,914)	(3,468,554)
Cumulative convertible preferred stock dividend requirement	(128,231)	(130,415)
NET LOSS AVAILABLE TO COMMON SHAREHOLDERS	$ (2,583,145)	$ (3,598,969)
NET INCOME (LOSS) PER COMMON SHARE
Loss on continuing operations	$ (0.05)	$ (0.08)
Income from discontinued operations	0	0.01
NET LOSS PER COMMON SHARE, basic and diluted	$ (0.05)	$ (0.07)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING, Basic and diluted	51,523,816	51,487,373

Statements of Changes in Stockh

Statements of Changes in Stockholders' Deficit - USD ($)	Series A Convertible Preferred Stock	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning balance, value at Feb. 29, 2016	$ 725	$ 51,487	$ 22,968,714	$ (32,410,915)	$ (9,389,989)
Beginning balance, shares at Feb. 29, 2016	724,565	51,487,373
Extension of 12% Note warrants			29,075		29,075
Net loss	$ 0	$ 0	0	(3,468,554)	(3,468,554)
Ending balance, value at Feb. 28, 2017	$ 725	$ 51,487	22,997,789	(35,879,469)	(12,829,468)
Ending balance, shares at Feb. 28, 2017	724,565	51,487,373
Conversion of preferred stock, value	$ (15)	$ 45	(30)
Conversion of preferred stock, shares	(14,997)	44,991
Net loss	$ 0	$ 0	0	(2,454,914)	(2,454,914)
Ending balance, value at Feb. 28, 2018	$ 710	$ 51,532	$ 22,997,759	$ (38,334,383)	$ (15,284,382)
Ending balance, shares at Feb. 28, 2018	709,568	51,532,364

Statements of Changes in Stock6

Statements of Changes in Stockholders' Deficit (Parenthetical)	Feb. 28, 2018	Feb. 28, 2017
Statement of Stockholders' Equity [Abstract]
Rate of note warrants	12.00%	12.00%

Statements of Cash Flows

Statements of Cash Flows - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$ (2,454,914)	$ (3,468,554)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Loss on sale of crude oil and natural gas properties	0	1,955,315
Loss on settlement of Note Receivable	0	1,500,676
Gain on debt settlement	0	(3,926,468)
Depreciation, depletion, and amortization	82,707	234,454
Amortization of debt discount	14,538	73,162
Amortization of deferred financing costs	238,598	423,331
Reclass of unproved crude oil and natural gas properties to exploration expenses	51,486	0
Debt modification fees	0	1,057,042
Interest income	31	81
Changes in assets and liabilities:
Accounts receivable - crude oil and natural gas sales	(21,435)	(21,332)
Accounts receivable - joint interest participants	(3,298)	51,540
Accounts receivable - other	4,489	(711,987)
Prepaid expenses and other current assets	3,729	86,819
Accounts payable and other accrued liabilities	305,368	395,814
Accounts payable - related parties	250,364	423,998
Accrued interest	1,408,169	2,092,076
Net cash provided by (used in) operating activities	(120,168)	165,967
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties	0	(73,683)
Prepaid drilling costs	0	(22,276)
Net cash used in investing activities	0	(95,959)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debt	102,700	25,000
Additions to line of credit	84,000	0
Payments on line of credit	(60,000)	(60,000)
Net cash provided by (used in) financing activities	126,700	(35,000)
NET INCREASE IN CASH AND CASH EQUIVALENTS	6,532	35,008
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	42,003	6,995
CASH AND CASH EQUIVALENTS AT END OF PERIOD	48,535	42,003
Cash paid for Interest	111,195	98,659
Cash paid for Income taxes	0	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest and fees converted to principal on debt	0	1,567,795
Increase in note receivable for interest added to principal	0	745,163
Satisfaction of note receivable through debt reduction	0	3,900,000
ARO revision	64,206	11,806
Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt	0	600,000
Proceeds from debt paid directly to accounts payable vendor	10,650	0
Unpaid deferred financing costs	0	20,854
Non-cash addition to debt for unproved O&G properties and prepaid drilling costs	0	84,000
Non-cash addition to debt for expenses paid directly by lender	0	215,000
Non-cash addition to line of credit due to monthly interest	31,728	33,815
Debt discount addition due to debt modification	0	29,075
Conversion of preferred stock to common stock	$ 45	$ 0

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Feb. 28, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION: Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States. During 2005, management of the Company decided to enter the crude oil and natural gas exploration and production industry. On October 25, 2005, the Company’s shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company. All of the Company’s crude oil and natural gas production is sold under contracts that are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

Going Concern

Going Concern	12 Months Ended
	Feb. 28, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Going Concern	NOTE 2 — GOING CONCERN: Financial Condition Daybreak’s financial statements for the twelve months ended February 28, 2018 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. Daybreak has incurred net losses since inception and has accumulated a deficit of $38,334,383 and a working capital deficit of $16,009,456, which raises substantial doubt about the Company’s ability to continue as a going concern. Management Plans to Continue as a Going Concern The Company continues to implement plans to enhance its ability to continue as a going concern. Daybreak currently has a net revenue interest in 20 producing crude oil wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”). The revenue from these wells has created a steady and reliable source of revenue. The Company’s average working interest in these wells is 36.6% and the average net revenue interest is 28.4% for these same wells. The Company anticipates revenue will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and our project in Michigan. However given the current decline and instability in hydrocarbon prices, the timing of any drilling activity in California will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of our credit facility. The Company believes that our liquidity will improve when there is a sustained improvement in hydrocarbon prices. Daybreak’s sources of funds in the past have included the debt or equity markets and the sale of assets. While the Company has experienced revenue growth, which has resulted in positive cash flow from its crude oil and natural gas properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plans to continue as a going concern. Daybreak’s financial statements as of February 28, 2018 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Feb. 28, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Cash and Cash Equivalents Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less. The Company has in the past maintained balances in financial institutions where deposits may exceed the federally insured deposit limit of $250,000. The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash. Accounts Receivable The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2018 and 2017. Crude Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred. Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives. Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” The Company did not recognize any asset impairment for the twelve months ended February 28, 2018 and 2017, respectively. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income. Property and Equipment Fixed assets are stated at cost. Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years. Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years. Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves. Long Lived Assets The Company reviews long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable. The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets. If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows). Fair Value of Financial Instruments The carrying value of short-term financial instruments including cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and the line of credit approximated their fair values due to the relatively short period to maturity for these instruments. The long-term notes payable approximates fair value since the related rates of interest approximate current market rates. Share Based Payments Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” . The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year. The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed. Loss per Share of Common Stock Basic loss per share of Common Stock is calculated by dividing net loss available to common stockholders by the weighted average number of common shares issued and outstanding during the year. Diluted net loss per share is computed based on the weighted average number of common shares outstanding, increased by dilutive Common Stock equivalents. Common Stock equivalents are excluded from the calculations when their effect is anti-dilutive. Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from crude oil California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. At the Company’s East Slopes project in California we deal with only one buyer for the purchase of all crude oil production. The Company has no natural gas production in California. At February 28, 2018 and 2017, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production. The Company’s accounts receivable from continuing operations in California for crude oil sales at February 28, 2018 and 2017, respectively are set forth in the table below. February 28, 2018 February 28, 2017 Project Customer Accounts Receivable Crude Oil Sales Percentage Accounts Receivable Crude Oil Sales Percentage California – East Slopes Project (Crude oil) Plains Marketing $ 104,840 100.0% $ 83,405 100.0% Revenue Recognition Reclamation Bonds Asset Retirement Obligation (“ARO”) The Company follows the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” , Suspended Well Costs The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Income Taxes The Company follows the provisions of FASB ASC Topic 740, “Income Taxes ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. Use of Estimates and Assumptions In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions. These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties; • The valuation of unproved acreage and proved crude oil and natural gas properties to determine the amount of any impairment of crude oil and natural gas properties; • Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and • Estimates regarding the timing and cost of future abandonment obligations. Recent Accounting Pronouncements Accounting Standards Issued and Adopted In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09) In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. The purpose of Update 216-18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of-period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. The Company has evaluated the impact and timing of the adoption of ASU 2016-18 and has concluded it will not have a material impact on its financial statements. Reclassifications Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation. These reclassifications had no effect on previously reported net loss or accumulated deficit.

Accounts Receivable

Accounts Receivable	12 Months Ended
	Feb. 28, 2018
Receivables [Abstract]
Accounts Receivable	NOTE 4 — ACCOUNTS RECEIVABLE: Accounts receivable consists primarily of receivables from the sale of crude oil production from continuing operations by the Company and receivables from the Company’s working interest partners in crude oil projects in which the Company acts as Operator of the project. Crude oil sales receivables balances from continuing operations of $104,840 and $83,405 at February 28, 2018 and 2017, represent crude oil sales that occurred in February 2018 and 2017, respectively. Joint interest participant receivables balances of $58,452 and $55,154 at February 28, 2018 and 2017, respectively, represent amounts due from working interest partners in California, where the Company is the Operator. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2018 and 2017.

Crude Oil Properties

Crude Oil Properties	12 Months Ended
	Feb. 28, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude Oil Properties	NOTE 5 — CRUDE OIL PROPERTIES: Crude oil property balances from continuing operations at February 28, 2018 and 2017 are set forth in the table below: February 28, 2018 (1) February 28, 2017 Proved leasehold costs $ 115,119 $ 115,119 Unproved leasehold costs 31,187 59,375 Costs of wells and development 2,293,668 2,293,668 Capitalized exploratory well costs 1,333,785 1,341,494 Capitalized asset retirement costs - 56,497 Total cost of oil and gas properties 3,773,759 3,866,153 Accumulated depletion, depreciation amortization and impairment (3,027,963) (2,953,226) Oil and gas properties, net $ 745,796 $ 912,927 (1)

Asset Retirement Obligation (AR

Asset Retirement Obligation (ARO)	12 Months Ended
	Feb. 28, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation (ARO)	NOTE 6 — Asset Retirement Obligation (“ARO”) The Company’s financial statements reflect the provisions of ASC 410. The ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determines the ARO on its crude oil and natural gas properties by calculating the present value of estimated cash flows related to the liability. As of February 28, 2018 and 2017, ARO obligations were considered to be long-term based on the estimated timing of the anticipated cash flows. For the twelve months ended February 28, 2018 and 2017, the Company recognized accretion expense of $7,971 and $8,390, respectively which is included in DD&A in the statement of operations. Changes in the asset retirement obligations for the twelve months ended February 28, 2018 and 2017 are set forth in the table below. February 28, 2018 February 28, 2017 Asset retirement obligation, beginning of period $ 93,409 $ 73,213 Accretion expense 7,971 8,390 Revisions to asset retirement obligation (64,206) 11,806 Asset retirement obligation, end of period $ 37,174 $ 93,409

Discontinued Operations

Discontinued Operations	12 Months Ended
	Feb. 28, 2018
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	NOTE 7 — DISCONTINUED OPERATIONS: Effective October 31, 2016, the Company finalized the sale of its interest in the Twin Bottoms Field in Kentucky. The sale included Daybreak’s working interest in 14 producing horizontal crude oil wells, its mineral rights, its lease acreage and infrastructure. In accordance with the guidance provided in ASC 205-20, the Company concluded that this sale qualified for presentation as discontinued operations. The Company has no ongoing or future plans to be involved in this segment of its crude oil and natural gas projects. Prior period income statement balances applicable to the Twin Bottoms Field in Kentucky have been reclassified and are included under the Discontinued Operations caption in the statements of operations for February 28, 2017. Operating income, interest income, operating expenses and interest expense related to Kentucky for the twelve months ended February 28, 2018 and 2017 are set forth in the tables below. For the Twelve Months Ended February 28, 2018 February 28, 2017 Crude oil and natural gas sales revenue $ - $ 280,030 Interest income - 760,704 Production, exploration and drilling expenses - (65,157) Depreciation, Depletion and Amortization (“DD&A”) expenses - (124,169) General and Administrative (G&A) - (204,056) Interest expense - (723,206) Loss on note receivable settlement - (1,500,676) Loss on sale of O&G properties - (1,955,315) Gain on debt settlement - 3,926,468 Loss from discontinued operations $ - $ (394,623) The statements of cash flows include certain significant non-cash operating items for discontinued operations in Kentucky during the twelve months ended February 28, 2017, comprised of loss on sale of crude oil and natural gas properties of $1.96 million; loss on note receivable settlement of $1.5 million; gain on debt settlement of $3.9 million; satisfaction of note receivable through debt reduction of $3.9 million; proceeds from sale of crude oil and natural gas properties paid directly to reduce debt of $600 thousand; addition to debt for expenses directly by lender of $215 thousand; increase in note receivable for interest added to principal of $745 thousand; DD&A expense of $124 thousand; and additions to crude oil and natural gas properties of $13 thousand.

Accounts Payable

Accounts Payable	12 Months Ended
	Feb. 28, 2018
Payables and Accruals [Abstract]
Accounts Payable	NOTE 8 — ACCOUNTS PAYABLE: On March 1, 2009, the Company became the operator for the East Slopes Project located in Kern County, California. Additionally, the Company then assumed certain original defaulting partners’ approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning wells program. The Company subsequently sold the 25% working interest on June 11, 2009. Approximately $244,849 of the $1.5 million default remains unpaid and is included in the February 28, 2018 accounts payable balance.

Accounts Payable - Related Part

Accounts Payable - Related Parties	12 Months Ended
	Feb. 28, 2018
Related Party Transactions [Abstract]
Accounts Payable - Related Parties	NOTE 9 — ACCOUNTS PAYABLE- RELATED PARTIES: The February 28, 2018 and 2017 accounts payable – related parties balances of $1,664,845 and $1,414,481, respectively, were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; related party consulting fees; and deferred interest payments on the 12% Subordinated Note to the Company’s Chairman, President and Chief Executive Officer. Payment of these deferred items has been delayed until the Company’s cash flow situation improves.

Short-Term and Long-Term Borrow

Short-Term and Long-Term Borrowings	12 Months Ended
	Feb. 28, 2018
Debt Disclosure [Abstract]
Short-Term and Long-Term Borrowings	NOTE 10— SHORT-TERM AND LONG-TERM BORROWINGS: Note Payable – Related Party The Company has a note payable - related party loan balance of $250,100 as of February 28, 2018 and 2017. The Company’s Chairman, President and Chief Executive Officer has loaned the Company an aggregate $250,100 that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future. 12% Subordinated Notes The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a January 2010 private placement offering to accredited investors, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the Notes were extended for an additional two years to January 29, 2019. There are ten noteholders, holding 980,000 warrants, who have not yet exercised their warrants. The exercise price of the associated warrants was lowered from $0.14 to $0.07 as a part of the Note maturity extension. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%. The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018. Amortization expense was $14,538 and $1,211 at February 28, 2018 and 2017, respectively. The unamortized debt discount at February 28, 2018 and 2017 was $13,326 and $27,864, respectively. 12% Note balances at February 28, 2018 and 2017 are set forth in the table below: February 28, 2018 February 28, 2017 12% Subordinated Notes $ 315,000 $ 315,000 Debt discount (7,429) (15,535) Net 12% Subordinated Note balance $ 307,571 $ 299,465 12% Note balances – related parties at February 28, 2018 and 2017 are set forth in the table below: February 28, 2018 February 28, 2017 12% Subordinated Notes – related party $ 250,000 $ 250,000 Debt discount (5,897) (12,329) Net 12% Subordinated Note – related party balance $ 244,103 $ 237,671 In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement. The warrants have an exercise price of $0.07 and an amended expiration date of January 29, 2019. The 12% Note warrants that have been exercised are set forth in the table below. At February 28, 2018, there were 980,000 warrants that were not exercised and had not expired. Fiscal Period Warrants Exercised Shares of Common Stock Issued Number of Accredited Investors Year Ended February 28, 2014 100,000 100,000 1 Year Ended February 28, 2015 50,000 50,000 1 Year Ended February 29, 2016 - - - Year Ended February 28, 2017 - - - Year Ended February 28, 2018 - - - Totals 150,000 150,000 2 Maximilian Credit Facility and Loan Agreement On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), which provided for a revolving credit facility of up to $20 million, that matured on October 31, 2016, with a minimum commitment of $2.5 million. On October 31, 2016 through the Fourth Amendment to the Amended and Restated Loan and Security Agreement, the maturity date of the loan was changed to February 28, 2020. In connection with the Company’s acquisition of a working interest from App Energy, LLC, a Kentucky limited liability company (“App Energy”) in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013. The amendment increased the amount of the credit facility to $90 million and reduced the annual interest rate to 12%. The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Company’s borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement. Consequently, the unamortized discount and the deferred financing costs as of the date of amendment were amortized over the term of the loan agreement. Due to the Company’s default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the twelve months ended February 28, 2018. On October 31, 2016, the Company entered into a Fourth Amendment to the Amended and Restated Loan and Security Agreement with Maximilian, which amended the Company’s loan agreement with Maximilian (the “Restructuring Agreement”). Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company had agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the following six month period and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale. During the twelve months ended February 28, 2017, approximately $1.5 million of interest was converted to principal. Additionally, as a consequence of the Company selling its’ Kentucky project and the settlement of the account receivable owed by App Energy to the Company $745,163 of interest was added to the note receivable principal; $600,000 of the sale proceeds were paid directly to Maximilian; and, a $3.9 million in reduction in debt owed to Maximilian occurred. As a result of the decline in hydrocarbon prices that started in June of 2014, the Company has been unable to make any type of interest or principal payments required under the amended terms of its credit facility with Maximilian since December of 2015. Under the terms of the Restructuring Amendment all unpaid interest is currently being accrued. Accrued interest on the credit facility loan at February 28, 2018 and 2017 was $1,812,128 and $440,389, respectively The Company is currently considered to be in default under the terms of its credit facility loan. Maximilian is currently in receivership. The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender to assume the Maximilian credit facility. No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company. During the twelve months ended February 28, 2018 and 2017, the Company received advances of $102,700 and $25,000, respectively, under the terms of the credit facility. Maximilian Promissory Note – Michigan Exploratory Joint Drilling Project As of February 28, 2018, the Company had received $94,650 in aggregate from multiple advances starting in the year ended February 28, 2017 from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an exploratory joint drilling project in Michigan. In the event of a default of any of the Company’s obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilian’s option. Advances under this agreement are subject to a 5% (five percent) per annum interest rate and may be prepaid at any time without penalty. Pursuant to the agreement, if a well that the Company elects to participate in is scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017, then the advances under the promissory note must be repaid in full upon the earlier of (a) the time that is ten days prior to the first well being spudded on the Michigan exploratory joint drilling project or (b) December 31, 2017. The agreement also provided that, if there was not a well scheduled to be spudded at the Michigan exploratory joint drilling project on or before December 31, 2017 that the Company elected to participate in, then the Company would assign to Maximilian its working interest in the Michigan exploratory joint drilling project, in full payment and satisfaction of the advances under the promissory note. Due to a lack of available funding from Maximilian, we were unable to spud a well on the Michigan project by December 31, 2017. The Company is currently considered to be in default under the terms of its loan agreement. Maximilian is currently in receivership. The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender. No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company. Accrued interest on the Michigan promissory note at February 28, 2018 and 2017 was $5,158 and $456, respectively. During the twelve months ended February 28, 2018, an aggregate amount of $10,650 was paid directly to the Operator of the Michigan project by Maximilian on the Company’s behalf. In accordance with the guidance found in ASC-470-10-45, the entire balance of the Maximilian loan is presented under the current liabilities section of the balance sheets. In accordance with the guidance found in ASC 835-30 the net amount of the deferred finance costs associated with the credit facility are included with the debt discount as a reduction of the loan balance shown on the Balance Sheet as of February 28, 2018 and 2017. Due to the Company’s default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the twelve months ended February 28, 2018. Current debt balances at February 28, 2018 and 2017 are set forth in the table below: February 28, 2018 February 28, 2017 Credit facility balance $ 9,063,144 $ 8,960,444 Less unamortized discount and debt issuance costs - (238,598) Subtotal – O&G operating debt 9,063,144 8,721,846 Michigan exploratory joint drilling debt 94,650 84,000 Net debt $ 9,157,794 $ 8,805,846 Deferred financing costs at February 28, 2018 and 2017 relating to the original and the amended credit facility with Maximilian, are set forth in the table below: February 28, 2018 February 28, 2017 Deferred financing costs – loan fees $ 181,648 $ 181,648 Deferred financing costs – loan commissions 630,662 630,662 Deferred financing costs – fair value of warrants 530,488 530,488 Deferred financing costs – fair value of common stock 419,832 419,832 Subtotal - deferred financing costs 1,762,630 1,762,630 Accumulated amortization (1,762,630) (1,524,032) Remaining balance - deferred financing costs $ - $ 238,598 Deferred financing cost balances of $-0- and $238,598 at February 28, 2018 and 2017, respectively includes the fair value of common shares and warrants issued to Maximilian and to a third party that assisted in both the original and the amended financing transactions. The unamortized deferred financing costs are netted against debt in the balance sheets. Amortization expense of deferred financing costs was $238,598 and $423,331 for the twelve months ended February 28, 2018 and 2017, respectively. Accrued interest on both the Maximilian credit facility loan and the Michigan loan at February 28, 2018 and 2017 was $1,817,286 and $$440,845, respectively. Encumbrances The Company’s debt obligations, pursuant to the above mentioned credit facility loan agreement and promissory notes entered into by and between Maximilian and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering its leases in California and the other covering its leases in Michigan. On July 13, 2017, in connection with receiving a payment waiver from Maximilian, the California and Michigan properties were cross-collateralized for the credit facility loan and the promissory note. Line of Credit The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Line of Credit Agreement dated October 24, 2011 that is secured by the personal guarantee of the Company’s Chairman, President and Chief Executive Officer. On July 10, 2017 a $700,000 portion of the outstanding line of credit balance was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining principal balance of the line of credit has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS. During the twelve months ended February 28, 2018 and 2017, we received advances on the line of credit of $84,000 and $-0-, respectively. During the twelve months ended February 28, 2018 and 2017, the Company made payments to the line of credit of $60,000 and $60,000, respectively. Interest paid for the twelve months ended February 28, 2018 and 2017 was $31,727 and $33,815, respectively. At February 28, 2018 and 2017, the line of credit had an outstanding balance of $873,350 and $817,622, respectively.

Stockholders' Deficit

Stockholders' Deficit	12 Months Ended
	Feb. 28, 2018
Equity [Abstract]
Stockholders' Deficit	NOTE 11 — STOCKHOLDERS’ DEFICIT: Preferred Stock The Company is authorized to issue up to 10,000,000 shares of preferred stock with a par value of $0.001. The Company’s preferred stock may be entitled to preference over the common stock with respect to the distribution of assets of the Company in the event of liquidation, dissolution, or winding-up of the Company, whether voluntarily or involuntarily, or in the event of any other distribution of assets of the Company among its shareholders for the purpose of winding-up its affairs. The authorized but unissued shares of preferred stock may be divided into and issued in designated series from time to time by one or more resolutions adopted by the Board of Directors. The directors in their sole discretion shall have the power to determine the relative powers, preferences, and rights of each series of preferred stock. Series A Convertible Preferred Stock The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value. In July 2006, we completed a private placement of the Series A Preferred that resulted in the issuance of 1,399,765 shares to 100 accredited investors. For the year ended February 28, 2018, there was one conversion of Series A Preferred stock to Common Stock. In this conversion, 14,997 shares of Series A Preferred were converted to 44,991 shares of the Company’s Common Stock. The following is a summary of the rights and preferences of the Series A Preferred. Voluntary Conversion: The Series A Preferred that is currently issued and outstanding is eligible to be converted by the shareholder at any time into three shares of the Company’s common stock. During the twelve months ended February 28, 2018, there was one conversion of 14,997 shares of Series A Preferred to 44,991 shares of the Company’s Common Stock. For the twelve months ended February 28, 2017, there were no conversions of Series A Preferred. At February 28, 2018 there were 709,568 shares issued and outstanding that had not been converted into our common stock. As of February 28, 2018, 44 accredited investors have converted 690,197 Series A Preferred shares into 2,070,591 shares of Daybreak Common Stock. The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below. Fiscal Period Shares of Series A Preferred Converted to Common Stock Shares of Common Stock Issued from Conversion Number of Accredited Investors Year Ended February 29, 2008 102,300 306,900 10 Year Ended February 28, 2009 237,000 711,000 12 Year Ended February 28, 2010 51,900 155,700 4 Year Ended February 28, 2011 102,000 306,000 4 Year Ended February 29, 2012 - - - Year Ended February 28, 2013 18,000 54,000 2 Year Ended February 28, 2014 151,000 453,000 9 Year Ended February 28, 2015 3,000 9,000 1 Year Ended February 29, 2016 10,000 30,000 1 Year Ended February 28, 2017 - - - Year Ended February 28, 2018 14,997 44,991 1 Totals 690,197 2,070,591 44 Automatic Conversion: The Series A Preferred shall be automatically converted into the Company’s common stock if the common stock into which the Series A Preferred are convertible the Company’s common stock closes at or above $3.00 per share for 20 out of 30 trading days. Dividend: Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends may be paid in cash or common stock at the discretion of the Company. Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends. Accumulations of dividends on shares of Series A Preferred do not bear interest. Dividends are payable upon declaration by the Board of Directors. Cumulative dividends earned for each twelve month period since issuance are set forth in the table below: Fiscal Year Ended Shareholders at Period End Accumulated Dividends February 28, 2007 100 $ 155,311 February 29, 2008 90 242,126 February 28, 2009 78 209,973 February 28, 2010 74 189,973 February 28, 2011 70 173,707 February 29, 2012 70 163,624 February 28, 2013 68 161,906 February 28, 2014 59 151,323 February 28, 2015 58 132,634 February 29, 2016 57 130,925 February 28, 2017 57 130,415 February 28, 2018 56 128,231 $ 1,970,148 Liquidation Preference: In the event of any liquidation, dissolution or winding up of the Company, either voluntary or involuntary, the holders of the Series A Preferred shall be entitled to receive, prior and in preference to any distribution of any of the assets or surplus funds of the Company to the holders of common stock by reason of their ownership thereof, and subject to the rights of any series of preferred stock that may rank on liquidation prior to the Series A Preferred, an amount equal to all accrued or declared but unpaid dividends on such shares, for each share of Series A Preferred then held by them. The remaining assets shall be distributed ratably to the holders of common stock and Series A Preferred on a common equivalent basis. Certain other events, as described in our Amended and Restated Articles of Incorporation, including a consolidation or merger of the Company or the disposition of the Company’s assets, may trigger the payment of the liquidation preference to the holders of Series A Preferred. Voting Rights: The holders of the Series A Preferred will vote together with the common stock and not as a separate class except as specifically provided or as otherwise required by law. Each share of the Series A Preferred shall have a number of votes equal to the number of shares of common stock then issuable upon conversion of such shares of Series A Preferred. Common Stock The Company is authorized to issue up to 200,000,000 shares of $0.001 par value Common Stock of which 51,532,364 and 51,487,373 shares were issued and outstanding as of February 28, 2018 and 2017, respectively. Common Stock Balance Par Value Common stock, Issued and Outstanding, February 29, 2016 51,487,373 Conversion of Series A Convertible Preferred Stock to common stock - $ - Common stock, Issued and Outstanding, February 28, 2017 51,487,373 Conversion of Series A Convertible Preferred Stock to common stock 44,991 $ 45 Common stock, Issued and Outstanding, February 28, 2018 51,532,364 All shares of common stock are equal to each other with respect to voting, liquidation, dividend and other rights. Owners of shares of common stock are entitled to one vote for each share of common stock owned at any shareholders’ meeting. Holders of shares of common stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefore; and upon liquidation, are entitled to participate pro rata in a distribution of assets available for such a distribution to shareholders. There are no conversion, preemptive, or other subscription rights or privileges with respect to any shares of our common stock. Our stock does not have cumulative voting rights, which means that the holders of more than 50% of the shares voting in an election of directors may elect all of the directors if they choose to do so. In such event, the holders of the remaining shares aggregating less than 50% would not be able to elect any directors.

Warrants

Warrants	12 Months Ended
	Feb. 28, 2018
Equity [Abstract]
Warrants	NOTE 12 — WARRANTS: Warrants outstanding and exercisable as of February 28, 2018 are set forth in the table below: Warrants Exercise Price Remaining Life (Years) Exercisable Warrants Remaining 12% Subordinated Notes 980,000 $0.07 0.92 980,000 Warrants issued for Kentucky crude oil project 3,498,601 $0.04 0.50 3,498,601 Warrants issued for Kentucky debt financing 2,623,951 $0.04 0.50 2,623,951 Warrants issued for Kentucky debt financing 309,503 $0.214 0.50 309,503 Warrants issued in share-for-warrant exchange 427,729 $0.04 0.50 427,729 7,839,784 7,839,784 Warrant activity for the twelve months ended February 28, 2018 and 2017 is set forth in the table below: Warrants Weighted Average Exercise Price Warrants outstanding, February 29, 2016 8,156,401 $0.06 Changes during the twelve months ended February 28, 2017: Expired / Cancelled / Forfeited - Warrants outstanding, February 28, 2017 8,156,401 $0.05 Changes during the twelve months ended February 28, 2018: Expired / Cancelled / Forfeited (316,617) Warrants outstanding, February 28, 2018 7,839,784 $0.05 Warrants exercisable, February 28, 2018 7,839,784 $0.05 On January 29, 2017, the 980,000 warrants associated with the 12% Subordinated Notes were modified to extend the expiration date of the warrants to January 29, 2019. As a part of this modification the exercise price of the 12% Note warrants was changed from $0.14 to $0.07. No other terms of the warrants were affected by the modification. The outstanding warrants as of February 28, 2018 and 2017 have a weighted average exercise price of $0.05; a weighted average remaining life of 0.55 and 1.52, respectively; and an intrinsic value of $-0-.

Income Taxes

Income Taxes	12 Months Ended
	Feb. 28, 2018
Income Tax Disclosure [Abstract]
Income Taxes	NOTE 13 INCOME TAXES: On December 22, 2017, the federal government enacted a tax bill H.R.1, an act to provide for reconciliation pursuant to Titles II and V of the concurrent resolution on the budget for fiscal year 2018, commonly referred to as the Tax Cuts and Jobs Act. The Tax Cuts and Jobs Act contains significant changes to corporate taxation, including, but not limited to, reducing the U.S. federal corporate income tax rate from 35% to 21% and modifying or limiting many business deductions. At Febraury 28, 2018, we had not completed our accounting for the tax effects resulting from the enactment of the Tax Cuts and Jobs Act; however we have made a reasonable estimate of the effects on our existing deferred tax balances. We remeasured deferred tax liabilities based on rates at which they are expected tobe utilized in the future, which is generally 21%. However, we are still analyzing certain aspecs of the Tax Cuts and Jobs Act and refining our calculations, which could potentially affect the measurement of those balances or give rise to new deferred tax amounts. Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rate to income from continuing operations before income taxes is as follows: February 28, 2018 February 28, 2017 Computed at U.S. and state statutory rates (40%) $ (981,966) $ (1,387,422) Permanent differences 29,060 83,606 New tax law adjustment 2,912,689 Changes in valuation allowance (1,959,783) 1,303,816 Total $ - $ - Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are presented below: February 28, 2018 February 28, 2017 Deferred tax assets: Net operating loss carryforwards $ 8,413,128 $ 10,425,780 Oil and gas properties 47,434 32,488 Stock based compensation 66,187 88,723 Other 27,838 (32,618) Less valuation allowance (8,554,587) (10,514,373) Total $ - $ - At February 28, 2018, the Company had a net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $27,853,381, which will begin to expire, if unused, beginning in 2024. Under the Tax Cuts and Jobs Act, the NOL portion of loss incurred in the 2018 period of $340,749 will not expire and will carry over indefinitely. The valuation allowances increased by $1,959,786 and $1,303,816 for the years ended February 28, 2018 and 2017, respectively. Section 382 Rule of the Internal Revenue Code will place annual limitations on the Company’s NOL carryforward. The above estimates are based upon management’s decisions concerning certain elections that could change the relationship between net income and taxable income. Management decisions are made annually and could cause the estimates to vary significantly. The Company’s files federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for the fiscal years after 2012 currently remain subject to examinations by appropriate tax authorities. None of our tax returns are under examination at this time.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Feb. 28, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 14 — COMMITMENTS AND CONTINGENCIES: Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities. While the ultimate outcome of the aforementioned contingencies are not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company. The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of February 28, 2018. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties. The Company’s minimum annual office rental lease commitments by fiscal year as of February 28, 2018 for these offices are shown in the table below: Fiscal Year Ended Annual Office Lease Obligation February 28, 2019 $ 12,849 February 29, 2020 - February 28, 2021 - February 28, 2022 - February 28, 2023 and thereafter - Totals $ 12,849

Subsequent Events

Subsequent Events	12 Months Ended
	Feb. 28, 2018
Subsequent Events [Abstract]
Subsequent Events	NOTE 15 — SUBSEQUENT EVENTS: On March 29, 2018 the restrictions on the pledged certificate of deposit with the State of California as a reclamation bond were lifted. These funds then became available for the Company to use for regular business purposes. The February 28, 2018 balance of this restricted time deposit was $100,029.

Supplementary Information for C

Supplementary Information for Crude Oil Producing Activities	12 Months Ended
	Feb. 28, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplementary Information for Crude Oil Producing Activities	NOTE 16 SUPPLEMENTARY INFORMATION FOR CRUDE OIL PRODUCING ACTIVITIES (UNAUDITED) Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities As of February 28, 2018 As of February 28, 2017 Proved leasehold costs Mineral Interests $ 115,119 $ 115,119 Wells, equipment and facilities 3,627,453 3,691,659 Total Proved Properties 3,742,572 3,806,778 Unproved properties Mineral Interests 31,187 59,375 Uncompleted wells, equipment and facilities - - Total unproved properties 31,187 59,375 Less accumulated depreciation, depletion amortization and impairment (3,027,963) (2,953,226) Net capitalized costs $ 745,796 $ 912,927 Costs Incurred in Oil and Gas Producing Activities 12 Months Ended 12 Months Ended February 28, 2018 February 28, 2017 Acquisition of proved properties $ - $ - Acquisition of unproved properties 31,187 59,375 Development costs - - Exploration costs - - Total costs incurred $ 31,187 $ 59,375 Results of Operations from Oil and Gas Producing Activities 12 Months Ended 12 Months Ended February 28, 2018 February 28, 2017 Oil and gas revenues $ 628,652 $ 762,686 Production costs (170,966) (221,579) Exploration expenses (107,884) (16,529) Depletion, depreciation and amortization (82,707) (234,454) Impairment of oil properties - - Result of oil and gas producing operations before income taxes 267,095 290,124 Provision for income taxes - - Results of oil and gas producing activities $ 267,095 $ 290,124 Proved Reserves The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, PGH Petroleum and Environmental Engineers, LLC. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors. On October 31, 2016, we sold our non-operated working interest in crude oil and natural gas properties located in the Twin Bottoms Field in Lawrence County, Kentucky. As of February 28, 2018, our total reserves were comprised of our working interest in East Slopes Project located in Kern County, California. Our proved reserves are summarized in the table below: Oil (Barrels) Natural Gas (Mcf) BOE (Barrels) Proved reserves: February 29, 2016 773,110 778,020 902,780 Revisions (1) (13,145) - (13,145) Sales of minerals (360,018) (761,517) (486,937) Production (18,877) (16,503) (21,628) February 28, 2017 381,070 - 381,070 Revisions (2) 35,099 - 35,099 Discoveries and extensions 24,639 - 24,639 Production (12,741) - (12,741) February 28, 2018 428,067 - 428,067 (1) The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets. (2) The revisions of previous estimates resulted from an increase in the estimated economic life of the reserves due to higher realized crude oil prices in the energy markets. The Company’s proved reserves are set forth in the table below. Developed Undeveloped Total Reserves Oil (Bbls) BOE (Bbls) Oil (Bbls) BOE (Bbls) Oil (Bbls) BOE (Bbls) February 28, 2018 109,475 109,475 318,592 318,592 428,067 428,067 February 28, 2017 99,710 99,710 281,360 281,360 381,070 381,070 February 29, 2016 203,131 231,778 569,979 671,002 773,110 902,780 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of February 28, 2018 and 2017 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves. Future cash inflows for the years ended February 28, 2018 and 2017 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from March through February during each respective fiscal year. The resulting net cash flows are reduced to present value by applying a 10% discount factor. 12 Months Ended February 28, 2018 February 28, 2017 Future cash inflows $ 21,526,541 $ 13,684,350 Future production costs (1) (10,373,652) (7,377,450) Future development costs (2,763,750) (2,090,810) Future income tax expenses (2) - - Future net cash flows 8,389,139 4,216,090 10% annual discount for estimated timing of cash flows (5,140,986) (2,493,750) Standardized measure of discounted future net cash flows at the end of the fiscal year $ 3,248,153 $ 1,722,340 (1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations. (2) The Company has sufficient tax deductions and allowances related to proved crude oil and natural gas reserves to offset future net revenues. Average hydrocarbon prices are set forth in the table below. Average Price Natural Crude Oil (Bbl) Gas (Mcf) Year ended February 28, 2018 (1) $ 50.29 $ - Year ended February 28, 2017 (1) $ 40.00 $ 1.59 Year ended February 29, 2016 (1) $ 47.45 $ 2.51 (1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year. Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions. Sources of Changes in Discounted Future Net Cash Flows Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below. 12 Months Ended February 28, 2018 February 28, 2017 Standardized measure of discounted future net cash flows at the beginning of the year $ 1,722,340 $ 3,972,930 Extensions, discoveries and improved recovery, less related costs 47,100 - Revisions of previous quantity estimates 267,955 (88,875) Sales of minerals in place - (1,948,968) Net changes in prices and production costs 1,355,682 (1,289,038) Accretion of discount 258,351 397,293 Sales of oil produced, net of production costs (457,686) (541,107) Development costs incurred during the period - 4,654 Changes in future development costs (265,044) 262,156 Changes in timing of future production 319,455 953,295 Net changes in income taxes - - Standardized measure of discounted future net cash flows at the end of the year $ 3,248,153 $ 1,722,340

Accounting Policies (Policies)

Accounting Policies (Policies)	12 Months Ended
	Feb. 28, 2018
Accounting Policies [Abstract]
Cash and Cash Equivalents	Cash and Cash Equivalents Cash equivalents include demand deposits with banks and all highly liquid investments with original maturities of three months or less. The Company has in the past maintained balances in financial institutions where deposits may exceed the federally insured deposit limit of $250,000. The Company has not experienced any losses from such accounts and does not believe it is exposed to any significant credit risk on cash.
Accounts Receivable	Accounts Receivable The Company routinely assesses the recoverability of all material trade and other receivables. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. Actual write-offs may exceed the recorded allowance. Substantially all of the Company’s trade accounts receivable result from crude oil in California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. Trade accounts receivable are generally not collateralized. There were no allowances for doubtful accounts for the Company’s trade accounts receivable at February 28, 2018 and 2017.
Crude Oil and Natural Gas Properties	Crude Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for crude oil and natural gas property acquisition, exploration, development, and production activities. Costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized as incurred. Costs to drill exploratory wells that are unsuccessful in finding proved reserves are expensed as incurred. In addition, the geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Costs to operate and maintain wells and field equipment are expensed as incurred. Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimated proved reserves. Capitalized exploration well costs and development costs (plus estimated future dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized in a similar fashion (by field) based on their estimated proved developed reserves. Support equipment and other property and equipment are depreciated over their estimated useful lives. Pursuant to the provisions of Financial Accounting Standards Codification (“ASC”) Topic 360, “Property, Plant and Equipment” The Company did not recognize any asset impairment for the twelve months ended February 28, 2018 and 2017, respectively. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated DD&A with a resulting gain or loss recognized in income.
Property and Equipment	Property and Equipment Fixed assets are stated at cost. Depreciation on vehicles is provided using the straight-line method over expected useful lives of three years. Depreciation on machinery and equipment is provided using the straight-line method over expected useful life of three years. Depreciation of production facilities and natural gas pipelines are recorded using the unit-of-production method based on estimated reserves.
Long Lived Assets	Long Lived Assets The Company reviews long-lived assets and identifiable intangibles whenever events or circumstances indicate that the carrying amounts of such assets may not be fully recoverable. The Company evaluates the recoverability of long-lived assets by measuring the carrying amounts of the assets against the estimated undiscounted cash flows associated with these assets. If this evaluation indicates that the future undiscounted cash flows of certain long-lived assets are not sufficient to recover the assets' carrying value, the assets are adjusted to their fair values (based upon discounted cash flows).
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying value of short-term financial instruments including cash, receivables, prepaid expenses, accounts payable, and other accrued liabilities, short-term liabilities and the line of credit approximated their fair values due to the relatively short period to maturity for these instruments. The long-term notes payable approximates fair value since the related rates of interest approximate current market rates.
Share Based Payments	Share Based Payments Stock awards are accounted for under FASB ASC Topic 718, “Compensation-Stock Compensation” . The Company estimates the fair value of stock purchase warrants on the grant date using the Black-Scholes option pricing model (“Black-Scholes Model”) as its method of valuation for warrant awards granted during the year. The Company’s determination of fair value of warrant awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected price volatility over the term of the awards and discount rates assumed.
Loss per Share of Common Stock	Loss per Share of Common Stock Basic loss per share of Common Stock is calculated by dividing net loss available to common stockholders by the weighted average number of common shares issued and outstanding during the year. Diluted net loss per share is computed based on the weighted average number of common shares outstanding, increased by dilutive Common Stock equivalents. Common Stock equivalents are excluded from the calculations when their effect is anti-dilutive.
Concentration of Credit Risk	Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from crude oil California or joint interest billings to its working interest partners in California. This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions as well as other related factors. At the Company’s East Slopes project in California we deal with only one buyer for the purchase of all crude oil production. The Company has no natural gas production in California. At February 28, 2018 and 2017, this one individual customer represented 100.0% of crude oil sales receivable from continuing operations. If this buyer is unable to resell its products or if they lose a significant sales contract then the Company may incur difficulties in selling its crude oil production.
Revenue Recognition	Revenue Recognition
Reclamation Bonds	Reclamation Bonds
Asset Retirement Obligation	Asset Retirement Obligation (“ARO”) The Company follows the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” ,
Suspended Well Costs	Suspended Well Costs The Company accounts for any suspended well costs in accordance with FASB ASC Topic 932, “Extractive Activities – Oil and Gas In addition, ASC 932 requires annual disclosure of: (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year, designating the number of wells the aging is related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation.
Income Taxes	Income Taxes The Company follows the provisions of FASB ASC Topic 740, “Income Taxes ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, the Company recognizes tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% (percent) likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards.
Use of Estimates and Assumptions	Use of Estimates and Assumptions In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions. These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties; • The valuation of unproved acreage and proved crude oil and natural gas properties to determine the amount of any impairment of crude oil and natural gas properties; • Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and • Estimates regarding the timing and cost of future abandonment obligations.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Accounting Standards Issued and Adopted In May 2014, the FASB issued ASC updated No. 2014-09, Revenue from Contracts with Customers (Topic 606 (ASU 2014-09) In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” (“ASU 2016-18”). The update is effective for years beginning December 15, 2017, including interim reporting periods within those fiscal years. Early adoption is permitted. The purpose of Update 216-18 is to clarify guidance and presentation related to restricted cash in the Statements of Cash Flows. The amendment requires beginning-of-period and end-of-period total amounts shown on the Statements of Cash Flows to include cash and cash equivalents as well as restricted cash and restricted cash equivalents. The Company has evaluated the impact and timing of the adoption of ASU 2016-18 and has concluded it will not have a material impact on its financial statements.
Reclassifications	Reclassifications Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation. These reclassifications had no effect on previously reported net loss or accumulated deficit.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Feb. 28, 2018
Accounting Policies [Abstract]
Schedule of Concentration of Risk, by Risk Factor	February 28, 2018 February 28, 2017 Project Customer Accounts Receivable Crude Oil Sales Percentage Accounts Receivable Crude Oil Sales Percentage California – East Slopes Project (Crude oil) Plains Marketing $ 104,840 100.0% $ 83,405 100.0%

Crude Oil Properties (Tables)

Crude Oil Properties (Tables)	12 Months Ended
	Feb. 28, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Crude Oil Activities	February 28, 2018 (1) February 28, 2017 Proved leasehold costs $ 115,119 $ 115,119 Unproved leasehold costs 31,187 59,375 Costs of wells and development 2,293,668 2,293,668 Capitalized exploratory well costs 1,333,785 1,341,494 Capitalized asset retirement costs - 56,497 Total cost of oil and gas properties 3,773,759 3,866,153 Accumulated depletion, depreciation amortization and impairment (3,027,963) (2,953,226) Oil and gas properties, net $ 745,796 $ 912,927 (1)

Asset Retirement Obligation (27

Asset Retirement Obligation (ARO) (Tables)	12 Months Ended
	Feb. 28, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligation	February 28, 2018 February 28, 2017 Asset retirement obligation, beginning of period $ 93,409 $ 73,213 Accretion expense 7,971 8,390 Revisions to asset retirement obligation (64,206) 11,806 Asset retirement obligation, end of period $ 37,174 $ 93,409

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Feb. 28, 2018
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Disposal Groups Including Discontinued Operations	For the Twelve Months Ended February 28, 2018 February 28, 2017 Crude oil and natural gas sales revenue $ - $ 280,030 Interest income - 760,704 Production, exploration and drilling expenses - (65,157) Depreciation, Depletion and Amortization (“DD&A”) expenses - (124,169) General and Administrative (G&A) - (204,056) Interest expense - (723,206) Loss on note receivable settlement - (1,500,676) Loss on sale of O&G properties - (1,955,315) Gain on ebbt settlement - 3,926,468 Loss from discontinued operations $ - $ (394,623)

Short-Term and Long-Term Borr29

Short-Term and Long-Term Borrowings (Tables)	12 Months Ended
	Feb. 28, 2018
Debt Disclosure [Abstract]
Schedule of Subordinated Notes	February 28, 2018 February 28, 2017 12% Subordinated Notes $ 315,000 $ 315,000 Debt discount (7,429) (15,535) Net 12% Subordinated Note balance $ 307,571 $ 299,465 February 28, 2018 February 28, 2017 12% Subordinated Notes – related party $ 250,000 $ 250,000 Debt discount (5,897) (12,329) Net 12% Subordinated Note – related party balance $ 244,103 $ 237,671
Schedule of Shares Issued and Warrants Exercised in Conjunction with Private Placement	Fiscal Period Warrants Exercised Shares of Common Stock Issued Number of Accredited Investors Year Ended February 28, 2014 100,000 100,000 1 Year Ended February 28, 2015 50,000 50,000 1 Year Ended February 29, 2016 - - - Year Ended February 28, 2017 - - - Year Ended February 28, 2018 - - - Totals 150,000 150,000 2
Schedule of Line of Credit Facilities	February 28, 2018 February 28, 2017 Credit facility balance $ 9,063,144 $ 8,960,444 Less unamortized discount and debt issuance costs - (238,598) Subtotal – O&G operating debt 9,063,144 8,721,846 Michigan exploratory joint drilling debt 94,650 84,000 Net debt $ 9,157,794 $ 8,805,846
Schedule of Deferred Financing Costs	February 28, 2018 February 28, 2017 Deferred financing costs – loan fees $ 181,648 $ 181,648 Deferred financing costs – loan commissions 630,662 630,662 Deferred financing costs – fair value of warrants 530,488 530,488 Deferred financing costs – fair value of common stock 419,832 419,832 Subtotal - deferred financing costs 1,762,630 1,762,630 Accumulated amortization (1,762,630) (1,524,032) Remaining balance - deferred financing costs $ - $ 238,598

Stockholders' Deficit (Tables)

Stockholders' Deficit (Tables)	12 Months Ended
	Feb. 28, 2018
Equity [Abstract]
Schedule of Stockholder's Equity	Fiscal Period Shares of Series A Preferred Converted to Common Stock Shares of Common Stock Issued from Conversion Number of Accredited Investors Year Ended February 29, 2008 102,300 306,900 10 Year Ended February 28, 2009 237,000 711,000 12 Year Ended February 28, 2010 51,900 155,700 4 Year Ended February 28, 2011 102,000 306,000 4 Year Ended February 29, 2012 - - - Year Ended February 28, 2013 18,000 54,000 2 Year Ended February 28, 2014 151,000 453,000 9 Year Ended February 28, 2015 3,000 9,000 1 Year Ended February 29, 2016 10,000 30,000 1 Year Ended February 28, 2017 - - - Year Ended February 28, 2018 14,997 44,991 1 Totals 690,197 2,070,591 44
Schedule of Dividends Payable	Fiscal Year Ended Shareholders at Period End Accumulated Dividends February 28, 2007 100 $ 155,311 February 29, 2008 90 242,126 February 28, 2009 78 209,973 February 28, 2010 74 189,973 February 28, 2011 70 173,707 February 29, 2012 70 163,624 February 28, 2013 68 161,906 February 28, 2014 59 151,323 February 28, 2015 58 132,634 February 29, 2016 57 130,925 February 28, 2017 57 130,415 February 28, 2018 56 128,231 $ 1,970,148
Schedule of Common Stock Outstanding	Common Stock Balance Par Value Common stock, Issued and Outstanding, February 29, 2016 51,487,373 Conversion of Series A Convertible Preferred Stock to common stock - $ - Common stock, Issued and Outstanding, February 28, 2017 51,487,373 Conversion of Series A Convertible Preferred Stock to common stock 44,991 $ 45 Common stock, Issued and Outstanding, February 28, 2018 51,532,364

Warrants (Tables)

Warrants (Tables)	12 Months Ended
	Feb. 28, 2018
Equity [Abstract]
Schedule of Stockholders' Equity Note Warrants and Rights	Warrants Exercise Price Remaining Life (Years) Exercisable Warrants Remaining 12% Subordinated Notes 980,000 $0.07 0.92 980,000 Warrants issued for Kentucky crude oil project 3,498,601 $0.04 0.50 3,498,601 Warrants issued for Kentucky debt financing 2,623,951 $0.04 0.50 2,623,951 Warrants issued for Kentucky debt financing 309,503 $0.214 0.50 309,503 Warrants issued in share-for-warrant exchange 427,729 $0.04 0.50 427,729 7,839,784 7,839,784
Schedule of Warrant Activity	Warrants Weighted Average Exercise Price Warrants outstanding, February 29, 2016 8,156,401 $0.06 Changes during the twelve months ended February 28, 2017: Expired / Cancelled / Forfeited - Warrants outstanding, February 28, 2017 8,156,401 $0.05 Changes during the twelve months ended February 28, 2018: Expired / Cancelled / Forfeited (316,617) Warrants outstanding, February 28, 2018 7,839,784 $0.05 Warrants exercisable, February 28, 2018 7,839,784 $0.05

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Feb. 28, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense Benefit	February 28, 2018 February 28, 2017 Computed at U.S. and state statutory rates (40%) $ (981,966) $ (1,387,422) Permanent differences 29,060 83,606 New tax law adjustment 2,912,689 - Changes in valuation allowance (1,959,783) 1,303,816 Total $ - $ -
Schedule of Deferred Tax Assets and Liabilities	February 28, 2018 February 28, 2017 Deferred tax assets: Net operating loss carryforwards $ 8,413,128 $ 10,425,780 Oil and gas properties 47,434 32,488 Stock based compensation 66,187 88,723 Other 27,838 (32,618) Less valuation allowance (8,554,587) (10,514,373) Total $ - $ -

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Feb. 28, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	Fiscal Year Ended Annual Office Lease Obligation February 28, 2019 $ 12,849 February 29, 2020 - February 28, 2021 - February 28, 2022 - February 28, 2023 and thereafter - Totals $ 12,849

Supplementary Information for34

Supplementary Information for Crude Oil Producing Activities (Tables)	12 Months Ended
	Feb. 28, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Relating to Crude Oil and Natural Gas Producing Activities	As of February 28, 2018 As of February 28, 2017 Proved leasehold costs Mineral Interests $ 115,119 $ 115,119 Wells, equipment and facilities 3,627,453 3,691,659 Total Proved Properties 3,742,572 3,806,778 Unproved properties Mineral Interests 31,187 59,375 Uncompleted wells, equipment and facilities - - Total unproved properties 31,187 59,375 Less accumulated depreciation, depletion amortization and impairment (3,027,963) (2,953,226) Net capitalized costs $ 745,796 $ 912,927
Cost Incurred in Oil and Gas Producing Activities	12 Months Ended 12 Months Ended February 28, 2018 February 28, 2017 Acquisition of proved properties $ - $ - Acquisition of unproved properties 31,187 59,375 Development costs - - Exploration costs - - Total costs incurred $ 31,187 $ 59,375
Results of Operations from Oil and Gas Producing Activities	12 Months Ended 12 Months Ended February 28, 2018 February 28, 2017 Oil and gas revenues $ 628,652 $ 762,686 Production costs (170,966) (221,579) Exploration expenses (107,884) (16,529) Depletion, depreciation and amortization (82,707) (234,454) Impairment of oil properties - - Result of oil and gas producing operations before income taxes 267,095 290,124 Provision for income taxes - - Results of oil and gas producing activities $ 267,095 $ 290,124
Schedule of Proved Developed and Undeveloped Oil and Gas Reserves	Oil (Barrels) Natural Gas (Mcf) BOE (Barrels) Proved reserves: February 29, 2016 773,110 778,020 902,780 Revisions (1) (13,145) - (13,145) Sales of minerals (360,018) (761,517) (486,937) Production (18,877) (16,503) (21,628) February 28, 2017 381,070 - 381,070 Revisions (2) 35,099 - 35,099 Discoveries and extensions 24,639 - 24,639 Production (12,741) - (12,741) February 28, 2018 428,067 - 428,067 (1) The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets. (2) The revisions of previous estimates resulted from an increase in the estimated economic life of the reserves due to higher realized crude oil prices in the energy markets. Developed Undeveloped Total Reserves Oil (Bbls) BOE (Bbls) Oil (Bbls) BOE (Bbls) Oil (Bbls) BOE (Bbls) February 28, 2018 109,475 109,475 318,592 318,592 428,067 428,067 February 28, 2017 99,710 99,710 281,360 281,360 381,070 381,070 February 29, 2016 203,131 231,778 569,979 671,002 773,110 902,780
Standardized Measure of Discounted Future Cash Flows Relating to Proved Oil and Gas Reserves	12 Months Ended February 28, 2018 February 28, 2017 Future cash inflows $ 21,526,541 $ 13,684,350 Future production costs (1) (10,373,652) (7,377,450) Future development costs (2,763,750) (2,090,810) Future income tax expenses (2) - - Future net cash flows 8,389,139 4,216,090 10% annual discount for estimated timing of cash flows (5,140,986) (2,493,750) Standardized measure of discounted future net cash flows at the end of the fiscal year $ 3,248,153 $ 1,722,340 (1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s oil and gas operations. (2) The Company has sufficient tax deductions and allowances related to proved crude oil and natural gas reserves to offset future net revenues.
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	Average Price Natural Crude Oil (Bbl) Gas (Mcf) Year ended February 28, 2018 (1) $ 50.29 $ - Year ended February 28, 2017 (1) $ 40.00 $ 1.59 Year ended February 29, 2016 (1) $ 47.45 $ 2.51 (1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	12 Months Ended February 28, 2018 February 28, 2017 Standardized measure of discounted future net cash flows at the beginning of the year $ 1,722,340 $ 3,972,930 Extensions, discoveries and improved recovery, less related costs 47,100 - Revisions of previous quantity estimates 267,955 (88,875) Sales of minerals in place - (1,948,968) Net changes in prices and production costs 1,355,682 (1,289,038) Accretion of discount 258,351 397,293 Sales of oil produced, net of production costs (457,686) (541,107) Development costs incurred during the period - 4,654 Changes in future development costs (265,044) 262,156 Changes in timing of future production 319,455 953,295 Net changes in income taxes - - Standardized measure of discounted future net cash flows at the end of the year $ 3,248,153 $ 1,722,340

Going Concern (Details Narrativ

Going Concern (Details Narrative)	Feb. 28, 2018USD ($)Number	Feb. 28, 2017USD ($)
Accumulated deficit	$ (38,334,383)	$ (35,879,469)
Working capital deficit	$ 16,009,456
Average Working and Revenue Interest | East Slopes Project
Number of producing wells, net revenue interest | Number	20
Average working interest	36.60%
Average net revenue interest	28.40%

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Schedule of Concentration of Risk, by Risk Factor (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Concentration Risk [Line Items]
Revenue receivable	$ 104,840	$ 83,405
Percent of revenue	100.00%	100.00%
Customer Concentration Risk | Accounts Receivable - Crude Oil Sales | Plains Marketing (California - East Slopes Project (Crude Oil))
Concentration Risk [Line Items]
Revenue receivable	$ 104,840	$ 83,405
Percent of revenue	100.00%	100.00%

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Property and Equipment
Expected useful lives	3 years	3 years
Concentration Risk
Concentration risk, customer	One individual customer	One individual customer
Crude oil and gas sales receivables, customer concentration	100.00%	100.00%
Asset Retirement Obligation
Reclamation bond	$ 100,000	$ 100,000

Accounts Receivable (Details Na

Accounts Receivable (Details Narrative) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Receivables [Abstract]
Accounts receivable - crude oil and natural gas sales	$ 104,840	$ 83,405
Accounts receivable - joint interest participants	$ 58,452	$ 55,154

Crude Oil Properties - Schedule

Crude Oil Properties - Schedule of Crude Oil Properties (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Oil and Natural Gas Property, Successful Effort Method, Net
Proved leasehold costs	$ 115,119	$ 115,119
Unproved leasehold costs	31,187	59,375
Costs of wells and development	2,293,668	2,293,668
Capitalized exploratory well costs	1,333,785	1,341,494
Capitalized asset retirement costs	0	56,497
Total cost of oil and gas properties	3,773,759	3,866,153
Accumulated depletion, depreciation, amortization and impairment	(3,027,963)	(2,953,226)
Oil and gas properties,net	$ 745,796	$ 912,927

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Properties (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Reduction in unproved crude oil and natural gas properties to exploration expenses	$ 51,486	$ 0

Asset Retirement Obligation (41

Asset Retirement Obligation (ARO) - Schedule of Changes in Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Asset Retirement Obligation, Roll Forward Analysis
Balance at beginning of period	$ 93,409	$ 73,213
Accretion expense	7,971	8,390
Revision to asset retirement obligation	(64,206)	11,806
Balance at end of period	$ 37,174	$ 93,409

Asset Retirement Obligation (42

Asset Retirement Obligation (ARO) (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Asset Retirement Obligation Disclosure [Abstract]
Accretion expense	$ 7,971	$ 8,390

Discontinued Operations - Sched

Discontinued Operations - Schedule of Disposal Groups Including Discontinued Operations (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on note receivable settlement	$ 0	$ (1,500,676)
Gain on debt settlement	0	3,926,468
Loss from discontinued operations	0	394,623
Twin Bottoms Field, Kentucky
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Crude oil and natural gas sales revenue	0	280,030
Interest income	0	760,704
Production, exploration and drilling expenses	0	(65,157)
Depreciation, Depletion and Amortization (DD&A) expenses	0	(124,169)
General and Administrative (G&A)	0	(204,056)
Interest expense	0	(723,206)
Loss on note receivable settlement	0	(1,500,676)
Loss on sale of O&G properties	0	(1,955,315)
Gain on debt settlement	0	3,926,468
Loss from discontinued operations	$ 0	$ (394,623)

Discontinued Operations (Detail

Discontinued Operations (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Loss on note receivable settlement	$ 0	$ (1,500,676)
Gain on debt settlement	0	3,926,468
Satisfaction of note receivable through debt reduction	0	3,900,000
Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt	0	600,000
Non-cash addition to debt for expenses paid directly by lender	0	215,000
Increase in note receivable for interest added to principal	0	745,163
Twin Bottoms Field, Kentucky
Loss on sale of O&G properties	0	(1,955,315)
Loss on note receivable settlement	0	(1,500,676)
Gain on debt settlement	0	3,926,468
Satisfaction of note receivable through debt reduction		3,900,000
Proceeds from sale of crude oil and natural gas properties paid directly to reduce debt		600,000
Non-cash addition to debt for expenses paid directly by lender		215,000
Increase in note receivable for interest added to principal		745,163
Depreciation, depletion and amortization (DD&A) expenses	$ 0	124,169
Unpaid additions to crude oil and natural gas properties		$ 13,000

Accounts Payable (Details Narra

Accounts Payable (Details Narrative)	12 Months Ended
	Feb. 28, 2018USD ($)
Payables and Accruals [Abstract]
Acquisition and disposition of East Slopes Project	On March 1, 2009, the Company became the operator for the East Slopes Project. The Company assumed certain original defaulting partners' approximate $1.5 million liability representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program. The Company subsequently sold the 25% working interest on June 11, 2009.
Accounts payable balance	$ 244,849

Accounts Payable - Related Pa46

Accounts Payable - Related Parties (Details Narrative) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Related Party Transactions [Abstract]
Accounts payable, related parties	$ 1,664,845	$ 1,414,481

Short-Term and Long-Term Borr47

Short-Term and Long-Term Borrowings - Subordinated Notes (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Debt Instrument [Line Items]
12% Notes payable, net	$ 0	$ 299,465
12% Note payable - related party, net	0	237,671
12% Subordinated Notes
Debt Instrument [Line Items]
Convertible subordinated debt, current	315,000	315,000
Debt discount	(7,429)	(15,535)
12% Notes payable, net	307,571	299,465
12% Subordinated Notes | Chief Executive Officer
Debt Instrument [Line Items]
Convertible subordinated debt, current	250,000	250,000
Debt discount	(5,897)	(12,329)
12% Note payable - related party, net	$ 244,103	$ 237,671

Short-Term and Long-Term Borr48

Short-Term and Long-Term Borrowings - Schedule of Shares Issued and Warrants Exercised with Private Placement (Details)	12 Months Ended
	Feb. 28, 2018Numbershares	Feb. 28, 2017Numbershares	Feb. 29, 2016Numbershares	Feb. 28, 2015Numbershares	Feb. 28, 2014Numbershares
Warrants exercised	150,000
Shares of common stock issued	150,000
Accredited investors | Number	44
12% Subordinated Notes
Warrants exercised	0	0	0	50,000	100,000
Shares of common stock issued	0	0	0	50,000	100,000
Accredited investors | Number	0	0	0	1	1

Short-Term and Long-Term Borr49

Short-Term and Long-Term Borrowings - Schedule of Line of Credit Facilities (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Line of Credit Facility [Line Items]
Credit facility balance	$ 873,350	$ 817,622
Less unamortized discount and debt issuance costs	(7,429)	0
Net debt	9,157,794	8,805,846
Revolving Credit Facility
Line of Credit Facility [Line Items]
Credit facility balance	9,063,144	8,960,444
Less unamortized discount and debt issuance costs	0	(238,598)
Subtotal - O&G operating debt	9,063,144	8,721,846
Michigan exploratory joint drilling debt	94,650	84,000
Net debt	$ 9,157,794	$ 8,805,846

Short-Term and Long-Term Borr50

Short-Term and Long-Term Borrowings - Schedule of Deferred Financing Costs (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Short-term Debt [Line Items]
Deferred financing costs, gross	$ 1,762,630	$ 1,762,630
Accumulated amortization	(1,762,630)	(1,524,032)
Deferred finance costs, net	0	238,598
Revolving Credit Facility | Common Stock
Short-term Debt [Line Items]
Deferred financing costs, gross	419,832	419,832
Revolving Credit Facility | Warrants
Short-term Debt [Line Items]
Deferred financing costs, gross	530,488	530,488
Revolving Credit Facility | Loan Commissions
Short-term Debt [Line Items]
Deferred financing costs, gross	630,662	630,662
Revolving Credit Facility | Loan Fees
Short-term Debt [Line Items]
Deferred financing costs, gross	$ 181,648	$ 181,648

Short-Term and Long-Term Borr51

Short-Term and Long-Term Borrowings (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017	Feb. 28, 2014	Feb. 28, 2013	Feb. 28, 2010
Debt Instrument [Line Items]
Interest rate	12.00%	12.00%
Warrants outstanding	7,839,784
Amortization of debt discount	$ 14,538	$ 73,162
Amortization of deferred financing costs	238,598	423,331
Deferred finance costs, net	0	238,598
Unamortized discount, noncurrent	0	15,535
Credit facility, advances	84,000	0
Payments on line of credit	60,000	60,000
Notes payable, related party	250,100	250,100
Interest converted to principal	0	1,567,795
Accrued interest added to note receivable	0	745,163
Accrued interest	1,817,286	440,845
Revolving Credit Facility | Maximilian Loan
Debt Instrument [Line Items]
Maximum borrowing				$ 20,000,000
Credit facility, advances	102,700	25,000
Credit facility, expiration date				Feb. 28, 2020
Minimum commitment fee				$ 2,500,000
Reduction in debt		3,900,000
Proceeds from sale of oil and gas properties		600,000
Interest converted to principal		1,500,000
Accrued interest added to note receivable		745,163
Accrued interest	1,812,128	440,389
Revolving Credit Facility | Maximilian Loan | Michigan Exploratory Joint Drilling Project
Debt Instrument [Line Items]
Credit facility, advances	$ 94,650
Line of credit, interest rate description	Advances under this agreement are subject to a 5% per annum interest rate.
Payments made on behalf of the company	$ 10,650
Accrued interest	5,158	$ 456
Revolving Credit Facility | Maximilian - Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Maximum borrowing			$ 90,000,000
Line of credit facility, interest rate			12.00%
Revolving Credit Facility | Maximilian - Fourth Amendment to Amended and Restated Loan Agreement
Debt Instrument [Line Items]
Credit facility, description		Pursuant to the Restructuring Agreement, in exchange for the proceeds it received from the Kentucky Sale, Maximilian and the Company have agreed to a commitment by Maximilian to advance up to $250,000 in financing to the Company over the next six months and the pursuit of the Michigan exploratory joint drilling project using the $250,000 set aside from the Kentucky Sale.
Maximum borrowing		$ 250,000
Line of Credit | UBS Bank USA
Debt Instrument [Line Items]
Maximum borrowing	890,000	890,000
Credit facility, advances	84,000	0
Line of credit, amount outstanding	873,350	817,622
Payments on line of credit	60,000	60,000
Line of credit, interest expense	$ 31,727	$ 33,815
Line of credit, interest rate description	On July 10, 2017 a portion of the outstanding credit line balance, $700,000, was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining balance of the credit line has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. The reference rate is based on the 30 day LIBOR ("London Interbank Offered Rate") and is subject to change from UBS.	Payable monthly at a stated reference rate of 0.249% + 337.5 basis points. The reference rate is based on the 30 day LIBOR ("London Interbank Offered Rate") and is subject to change from UBS.
12% Subordinated Notes
Debt Instrument [Line Items]
Interest rate					12.00%
Maturity date	Jan. 29, 2019	Jan. 29, 2019			Jan. 29, 2017
Payment terms					Payable semi-annually on January 29th and July 29th. Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2018.
Proceeds from subordinate notes					$ 595,000
Subordinate note, principal	$ 565,000
Warrants issued	1,190,000
Warrants outstanding	980,000	980,000
Warrants, exercise price	$ 0.07
Fair value of warrants	$ 29,075
Weighted average risk free interest rate	1.22%
Weighted average volatility rate	378.73%
Amortization of debt discount	$ 14,538	$ 1,211
Unamortized discount, noncurrent	13,326	27,864
Chief Executive Officer
Debt Instrument [Line Items]
Notes payable, related party	$ 250,100	$ 250,100

Stockholders' Deficit - Convers

Stockholders' Deficit - Conversions of Series A Preferred Stock (Details)	12 Months Ended
	Feb. 28, 2018Numbershares	Feb. 28, 2017Numbershares	Feb. 29, 2016Numbershares	Feb. 28, 2015Numbershares	Feb. 28, 2014Numbershares	Feb. 28, 2013Numbershares	Feb. 29, 2012Numbershares	Feb. 28, 2011Numbershares	Feb. 28, 2010Numbershares	Feb. 28, 2009Numbershares	Feb. 29, 2008Numbershares
Series A preferred shares converted to common stock	690,197
Shares of common stock issued from conversion	2,070,591
Accredited investors | Number	44
Series A Convertible Preferred Stock
Series A preferred shares converted to common stock	14,997	0	10,000	3,000	151,000	18,000	0	102,000	51,900	237,000	102,300
Shares of common stock issued from conversion	44,991	0	30,000	9,000	453,000	54,000	0	306,000	155,700	711,000	306,900
Accredited investors | Number	100	0	1	1	9	2	0	4	4	12	10

Stockholders' Deficit - Preferr

Stockholders' Deficit - Preferred Stock Dividends Earned (Details)	12 Months Ended
	Feb. 28, 2018USD ($)Number	Feb. 28, 2017USD ($)Number	Feb. 29, 2016USD ($)Number	Feb. 28, 2015USD ($)Number	Feb. 28, 2014USD ($)Number	Feb. 28, 2013USD ($)Number	Feb. 29, 2012USD ($)Number	Feb. 28, 2011USD ($)Number	Feb. 28, 2010USD ($)Number	Feb. 28, 2009USD ($)Number	Feb. 29, 2008USD ($)Number	Feb. 28, 2007USD ($)Number
Equity [Abstract]
Preferred shareholders at period end | Number	56	57	57	58	59	68	70	70	74	78	90	100
Earned dividends	$ 128,231	$ 130,415	$ 130,925	$ 132,634	$ 151,323	$ 161,906	$ 163,624	$ 173,707	$ 189,973	$ 209,973	$ 242,126	$ 155,311
Total accumulated dividends	$ 1,970,148

Stockholders' Deficit - Schedul

Stockholders' Deficit - Schedule of Common Stock Outstanding (Details)	12 Months Ended
	Feb. 28, 2018USD ($)shares
Equity [Abstract]
Common stock, Issued and Outstanding, beginning of period	51,487,373
Conversion of Series A Convertible Preferred Stock to common stock	44,991
Common stock, Issued and Outstanding, end of period	51,532,364
Conversion of Series A Convertible Preferred Stock to common stock, par value | $	$ 45

Stockholders' Deficit (Details

Stockholders' Deficit (Details Narrative)	12 Months Ended
	Feb. 28, 2018Number$ / sharesshares	Feb. 28, 2017Number$ / sharesshares	Feb. 29, 2016Numbershares	Feb. 28, 2015Numbershares	Feb. 28, 2014Numbershares	Feb. 28, 2013Numbershares	Feb. 29, 2012Numbershares	Feb. 28, 2011Numbershares	Feb. 28, 2010Numbershares	Feb. 28, 2009Numbershares	Feb. 29, 2008Numbershares
Preferred stock, par value in dollars | $ / shares	$ 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
Series A preferred shares converted to common stock	690,197
Shares of common stock issued from conversion	2,070,591
Accredited investors | Number	44
Common stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	51,532,364	51,487,373
Common stock, shares outstanding	51,532,364	51,487,373
Series A Convertible Preferred Stock
Preferred stock, par value in dollars | $ / shares	$ 0.001	$ 0.001
Preferred stock, shares authorized	2,400,000	2,400,000
Preferred stock, shares issued	709,568	724,565	1,399,765
Preferred stock, shares outstanding	709,568	724,565
Series A preferred shares converted to common stock	14,997	0	10,000	3,000	151,000	18,000	0	102,000	51,900	237,000	102,300
Shares of common stock issued from conversion	44,991	0	30,000	9,000	453,000	54,000	0	306,000	155,700	711,000	306,900
Preferred stock, cumulative dividend rate		6.00%
Accredited investors | Number	100	0	1	1	9	2	0	4	4	12	10

Warrants - Schedule of Stockhol

Warrants - Schedule of Stockholders' Equity Note Warrants and Rights (Details) - $ / shares	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Class of Warrant or Right [Line Items]
Warrants	7,839,784
Exercisable warrants remaining	7,839,784
Share-for-Warrant Exchange
Class of Warrant or Right [Line Items]
Warrants	427,729
Exercise price	$ 0.04
Remaining life (years)	6 months
Exercisable warrants remaining	427,729
Warrants | Kentucky Debt Financing #2
Class of Warrant or Right [Line Items]
Warrants	309,503
Exercise price	$ 0.214
Remaining life (years)	6 months
Exercisable warrants remaining	309,503
Warrants | Kentucky Debt Financing #1
Class of Warrant or Right [Line Items]
Warrants	2,623,951
Exercise price	$ 0.04
Remaining life (years)	6 months
Exercisable warrants remaining	2,623,951
Warrants | Kentucky Crude Oil Project
Class of Warrant or Right [Line Items]
Warrants	3,498,601
Exercise price	$ 0.04
Remaining life (years)	6 months
Exercisable warrants remaining	3,498,601
12% Subordinated Notes
Class of Warrant or Right [Line Items]
Warrants	980,000	980,000
Exercise price	$ 0.07
Remaining life (years)	6 months	1 year 6 months
Exercisable warrants remaining	980,000

Warrants - Schedule of Warrant

Warrants - Schedule of Warrant Activity (Details)	12 Months Ended
	Feb. 28, 2018$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Warrants outstanding, beginning of period	8,156,401
Expired / Cancelled / Forfeited	(316,617)
Warrants outstanding, end of period	7,839,784
Warrants exercisable, end of period	7,839,784
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date
Weighted average exercise price of warrants outstanding, beginning of period | $ / shares	$ 0.05
Weighted average exercise price of warrants outstanding, end of period | $ / shares	0.05
Weighted average exercise price of warrants exercisable, end of period | $ / shares	$ 0.05

Warrants (Details Narrative)

Warrants (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017	Feb. 28, 2010
Warrants outstanding	7,839,784
Warrants expired	(316,617)
12% Subordinated Notes
Warrants outstanding	980,000	980,000
Maturity date	Jan. 29, 2019	Jan. 29, 2019	Jan. 29, 2017
Warrants, exercise price	$ 0.07
Weighted average exercise price	$ 0.05	$ 0.05
Weighted average remaining life	6 months	1 year 6 months
Intrinsic value	$ 0	$ 0

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense Benefit Reconciliation (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation
Computed at U.S. and state statutory rates (40%)	$ (981,966)	$ (1,387,422)
Permanent differences	29,060	83,606
New tax law adjustment	2,912,689	0
Changes in valuation allowance	(1,959,783)	1,303,816
Income tax expense (benefit)	$ 0	$ 0

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Deferred tax assets:
Net operating loss carryforwards	$ 8,413,128	$ 10,425,780
Oil and gas properties	47,434	32,488
Stock based compensation	66,187	88,723
Other	27,838	(32,618)
Less valuation allowance	(8,554,587)	(10,514,373)
Deferred tax assets, net	$ 0	$ 0

Income Taxes (Details Narrative

Income Taxes (Details Narrative) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Income Tax Disclosure [Abstract]
Net operating loss carryforwards, federal and state, approximate	$ 27,853,381
NOL portion of loss incurred under the Tax Cutts and Jobs Act	$ 340,749
Net operating loss carryforwards, expiration date	Feb. 28, 2024
Approximate increase in valuation allowance	$ 1,959,786	$ 1,303,816

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details)	Feb. 28, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
February 28, 2019	$ 12,849
February 29, 2020	0
February 28, 2021	0
February 28, 2022	0
February 28, 2023 and thereafter	0
Totals	$ 12,849

Subsequent Events (Details Narr

Subsequent Events (Details Narrative)	Mar. 31, 2018USD ($)
Subsequent Event | Deposits
Subsequent Event [Line Items]
Deposits	$ 100,029

Supplementary Information - Cap

Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($)	Feb. 28, 2018	Feb. 28, 2017
Proved leasehold costs
Mineral Interests	$ 115,119	$ 115,119
Wells, equipment and facilities	3,627,453	3,691,659
Total Proved Properties	3,742,572	3,806,778
Unproved properties
Mineral Interests	31,187	59,375
Uncompleted wells, equipment and facilities	0	0
Total unproved properties	31,187	59,375
Less accumulated depreciation, depletion amortization and impairment	(3,027,963)	(2,953,226)
Net capitalized costs	$ 745,796	$ 912,927

Supplementary Information - Cos

Supplementary Information - Cost Incurred in Oil and Gas Producing Activities (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Costs Incurred Acquisition Of Oil And Gas Properties
Acquisition of proved properties	$ 0	$ 0
Acquisition of unproved properties	31,187	59,375
Development costs	0	0
Exploration costs	0	0
Total costs incurred	$ 31,187	$ 59,375

Supplementary Information - Res

Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Results Of Operations From Oil And Gas Producing Activities
Oil and gas revenues	$ 628,652	$ 762,686
Production costs	(170,966)	(221,579)
Exploration expenses	(107,884)	(16,529)
Depletion, depreciation and amortization	(82,707)	(234,454)
Impairment of oil properties	0	0
Result of oil and gas producing operations before income taxes	267,095	290,124
Provision for income taxes	0	0
Results of oil and gas producing activities	$ 267,095	$ 290,124

Supplementary Information - Sch

Supplementary Information - Schedule of Proved Oil and Gas Reserves (Details)	12 Months Ended
	Feb. 28, 2018Boebbl		Feb. 28, 2017Boebbl
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance	381,070		773,110
Proved reserves - ending balance	428,067		381,070
Proved Developed and Undeveloped Reserve (Energy)
Proved reserves - beginning balance | Boe	381,070		902,780
Proved reserves - ending balance | Boe	428,067		381,070
Oil (Barrels)
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance	381,070		773,110
Proved reserves - revisions	35,099	[1]	(13,145)	[2]
Proved reserves - discoveries and extensions	24,639
Proved reserves - sales of minerals			(360,018)
Proved reserves - production	(12,741)		(18,877)
Proved reserves - ending balance	428,067		381,070
Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves
Proved reserves - beginning balance	0		778,020
Proved reserves - revisions	0	[1]	0	[2]
Proved reserves - discoveries and extensions	0
Proved reserves - sales of minerals			(761,517)
Proved reserves - production	0		(16,503)
Proved reserves - ending balance			0
BOE (Barrels)
Proved Developed and Undeveloped Reserve (Energy)
Proved reserves - beginning balance | Boe	381,070		902,780
Proved reserves - revisions | Boe	35,099	[1]	(13,145)	[2]
Proved reserves - discoveries and extensions | Boe	24,639
Proved reserves - sales of minerals | Boe			(486,937)
Proved reserves - production | Boe	(12,741)		(21,628)
Proved reserves - ending balance | Boe	428,067		381,070
[1]	The revisions of previous estimates resulted from an increase in the estimated economic life of the reserves due to higher realized crude oil prices in the energy markets.
[2]	The revisions of previous estimates resulted from a decline in the estimated economic life of the reserves due to lower realized crude oil prices in the energy markets.

Supplementary Information - S68

Supplementary Information - Schedule of Proved Developed and Undeveloped Reserves (Details)	Feb. 28, 2018Boebbl	Feb. 28, 2017Boebbl	Feb. 29, 2016Boebbl
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, net | bbl	428,067	381,070	773,110
Proved developed and undeveloped reserves, net - BOE | Boe	428,067	381,070	902,780
Proved Developed Reserves
Reserve Quantities [Line Items]
Proved developed reserves | bbl	109,475	99,710	203,131
Proved developed reserves - BOE | Boe	109,475	99,710	231,778
Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved undeveloped reserves | bbl	318,592	281,360	569,979
Proved undeveloped reserves - BOE | Boe	318,592	281,360	671,002

Supplementary Information - Sta

Supplementary Information - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Details) - USD ($)		Feb. 28, 2018	Feb. 28, 2017	Feb. 29, 2016
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Standardized Measure
Future cash inflows		$ 21,526,541	$ 13,684,350
Future production costs	[1]	(10,373,652)	(7,377,450)
Future development costs		(2,763,750)	(2,090,810)
Future income tax expenses	[2]	0	0
Future net cash flows		8,389,139	4,216,090
10% annual discount for estimated timing of cash flows		(5,140,986)	(2,493,750)
Standardized measure of discounted future net cash flows at the end of the fiscal year		$ 3,248,153	$ 1,722,340	$ 3,972,930
[1]	Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company's crude oil and natural gas operations.
[2]	The Company has sufficient tax deductions and allowances related to proved crude oil and natural gas reserves to offset future net revenues.

Supplementary Information - Oil

Supplementary Information - Oil and Gas Net Production, Average Sales Price and Production Costs (Details) - $ / bbl		12 Months Ended
		Feb. 28, 2018	Feb. 28, 2017	Feb. 29, 2016
Crude Oil (Bbl)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average oil and gas sales price	[1]	50.29	40	47.45
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average oil and gas sales price	[1]	0	1.59	2.51
[1]	Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from March through February during each respective fiscal year.

Supplementary Information - S71

Supplementary Information - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	12 Months Ended
	Feb. 28, 2018	Feb. 28, 2017
Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the year	$ 1,722,340	$ 3,972,930
Extensions, discoveries and improved recovery, less related costs	47,100	0
Revisions of previous quantity estimates	267,955	(88,875)
Sales of minerals in place	0	(1,948,968)
Net changes in prices and production costs	1,355,682	(1,289,038)
Accretion of discount	258,351	397,293
Sales of oil produced, net of production costs	(457,686)	(541,107)
Development costs incurred during the period	0	4,654
Changes in future development costs	(265,044)	262,156
Changes in timing of future production	319,455	953,295
Net changes in income taxes	0	0
Standardized measure of discounted future net cash flows at the end of the year	$ 3,248,153	$ 1,722,340