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 Companys common stock at a conversion rate equal to 75% of the average closing price of the Companys 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 |