10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended July 31, 2017

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______.

Commission file number: 000-49760

PETRO RIVER OIL CORP.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	98-0611188
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

55 5th Avenue, Suite 1702, New York, NY 10003

(Address of Principal Executive Offices, Zip Code)

(469) 828-3900

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Sec.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [  ]	Accelerated filer [  ]	Non-accelerated filer [  ]	Smaller reporting company [X]
			Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided to Section 7(a)(2)(B) of the Securities Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [  ] No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at September 14, 2017
Common Stock, $0.00001 par value per share	15,843,142 shares

TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Consolidated Balance Sheets (Unaudited)	1
	Consolidated Statements of Operations (Unaudited)	2
	Consolidated Statements of Cash Flows (Unaudited)	3
	Notes to Consolidated Financial Statements (Unaudited)	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operation	19
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	26
Item 4.	Controls and Procedures	26
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Default Upon Senior Securities	28
Item 4.	Mine Safety Disclosures	28
Item 5.	Other Information	28
Item 6.	Exhibits	28
SIGNATURES		29

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

Petro River Oil Corp. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

	As of
	July 31, 2017	April 30, 2017
Assets
Current Assets:
Cash and cash equivalents	$1,167,124	$631,232
Accounts receivable - oil and gas	8,669	8,423
Accounts receivable - real estate - related party	1,146,673	2,123,175
Accrued interest on notes receivable - related party	992,309	797,710
Interest in real estate rights	-	309,860
Prepaid expenses and other current assets	32,367	207,831
Prepaid oil and gas asset development costs	894,879	613,480
Notes receivable - related party, current portion	26,344,883	24,786,382
Total Current Assets	30,586,904	29,478,093
Oil and gas assets, full cost method
Costs subject to amortization, net	1,973,313	1,234,806
Costs not being amortized, net	858,828	858,830
Property, plant and equipment, net of accumulated depreciation of $184,330 and $184,140, respectively	1,392	1,582
Investment in Horizon Energy Partners	1,592,418	1,213,000
Other assets	17,133	17,133
Total Long-term Assets	4,443,084	3,325,351
Total Assets	$35,029,988	$32,803,444
Liabilities and Equity
Current Liabilities:
Accounts payable and accrued expenses	$376,597	$120,233
Deferred tax liability	3,640,928	3,442,724
Asset retirement obligations, current portion	406,403	406,403
Total Current Liabilities	4,423,928	3,969,360
Long-term Liabilities:
Asset retirement obligations, net of current portion	162,764	152,293
Note payable, net of debt discount of $914,678 and $0, respectively	1,085,322	-
Total Long-term Liabilities	1,248,086	152,293
Total Liabilities	5,672,014	4,121,653
Commitments and contingencies
Equity:
Preferred shares - 5,000,000 authorized; par value $0.00001; 0 shares issued and outstanding	-	-
Preferred B shares - 29,500 authorized; par value $0.00001; 0 shares issued and outstanding	-	-
Common shares - 100,000,000 authorized; par value $0.00001; 15,840,143 and 15,827,921 issued and outstanding, respectively	158	158
Additional paid-in capital	48,162,461	46,681,073
Accumulated deficit	(31,489,686)	(30,609,910)
Total Petro River Oil Corp. Equity	16,672,933	16,071,321
Non-controlling interests	12,685,041	12,610,470
Total Equity	29,357,974	28,681,791
Total Liabilities and Equity	$35,029,988	$32,803,444

The accompanying notes are an integral part of these consolidated financial statements.

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Petro River Oil Corp. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	For the Three Months
	Ended
Operations	July 31, 2017	July 31, 2016
Revenues
Oil and natural gas sales	$8,803	$-
Total Revenues	8,803	-
Operating Expenses
Lease operating expenses	18,362	23,759
Depreciation, depletion and accretion	9,120	4,396
Gain on sale of oil and gas assets	-	(216,580)
General and administrative	992,557	1,708,141
Total Operating Expenses	1,020,039	1,519,716
Operating Loss	(1,011,236)	(1,519,716)
Other Income (Expense)
Interest income (expense) - net	132,745	141,259
Net gain on real estate rights	271,490	300,639
Other Income	404,235	441,898
Net Loss Before Income Tax Provision	(607,001)	(1,077,818)
Income Tax Provision	198,204	187,917
Net Loss	(805,205)	(1,265,735)
Net Income Attributable to Non-controlling Interest	74,571	47,675
Net Loss Attributable to Petro River Oil Corp. Shareholders	$(879,776)	$(1,313,410)
Basic and Diluted Net Loss Per Common Share	$(0.06)	$(0.09)
Weighted Average Number of Common Shares Outstanding - Basic and Diluted	15,835,095	15,450,826

The accompanying notes are an integral part of these consolidated financial statements.

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Petro River Oil Corp. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	For the Three Months
	Ended
	July 31, 2017	July 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$(805,205)	$(1,265,735)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Stock-based compensation	529,332	1,150,197
Depreciation, depletion and accretion	9,120	4,396
Amortization of debt discount	37,378	-
Gain on sale of oil and gas assets	-	(216,580)
Net gain on interest in real estate rights	(271,490)	(300,639)
Deferred income tax expense	198,204	187,917
Changes in operating assets and liabilities:
Accounts receivable – oil and gas	(246)	903
Accrued interest on notes receivable – related party	(194,599)	(141,259)
Prepaid expenses and other assets	175,464	(66,867)
Accounts payable and accrued expenses	256,364	(39,806)
Net Cash Used in Operating Activities	(65,678)	(687,473)
Cash Flows From Investing Activities:
Proceeds from the sale of interest in real estate rights	1,557,852	2,915,332
Prepaid oil and gas assets	(281,399)	(65,947)
Issuance of notes receivable – related party	(1,558,501)	(2,947,129)
Capitalized expenditures on oil and gas assets	(736,964)	(6,790)
Cash received from acquisition of Horizon Investments	-	3,364,817
Cash paid for cost method investment	(379,418)	(525,000)
Net Cash (Used in) Provided by Investing Activities	(1,398,430)	2,735,283
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from notes payable – related party	2,000,000	-
Net Cash Provided by Financing Activities	2,000,000	-
Change in cash and cash equivalents	535,892	2,047,810
Cash and cash equivalents, beginning of period	631,232	774,751
Cash and cash equivalents, end of period	$1,167,124	$2,822,561
SUPPLEMENTARY CASH FLOW INFORMATION:
Cash paid during the period for:
Income taxes	$34,052	$3,789
Interest paid	$-	$-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Reclassification from prepaid oil and gas development costs to oil and gas assets not being amortized	$-	$761,444
Asset retirement obligation from drilling activities	$7,500	-
Warrants issued with notes payable	$952,056	$-

The accompanying notes are an integral part of these consolidated financial statements. 

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PETRO RIVER OIL CORP.

Notes to the Consolidated Financial Statements

(Unaudited)

1. Organization

Petro River Oil Corp. (the “Company”) is an independent energy company focused on the exploration and development of conventional oil and gas assets with low discovery and development costs. The Company is currently focused on moving forward with drilling wells on several of its properties owned directly and indirectly through its interest in Horizon Energy Partners, LLC (“Horizon Energy”), as well as taking advantage of the relative depressed market in oil prices to enter highly prospective plays with Horizon Energy and other industry-leading partners. Diversification over a number of projects, each with low initial capital expenditures and strong risk reward characteristics, reduces risk and provides cross-functional exposure to a number of attractive risk adjusted opportunities.

The Company’s core holdings are in Osage County, Oklahoma and in Kern County, California.   Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company now has exposure to a portfolio of several domestic and international oil and gas assets consisting of highly prospective conventional plays diversified across project type, geographic location and risk profile, as well as access to a broad network of industry leaders from Horizon Investment’s 20% interest in Horizon Energy.  Horizon Energy is an oil and gas exploration and development company owned and managed by former senior oil and gas executives.  It has a portfolio of domestic and international assets, including two assets located in the United Kingdom, adjacent to the giant Wytch Farm oil field, the largest onshore oil field in Western Europe.  Other projects include the proposed redevelopment of a large oil field in Kern County, California and the development of an additional recent discovery in Kern County.  Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

In light of the challenging oil price environment and capital markets, management is focusing on specific target acquisitions and investments, limiting operating expenses and exploring farm-in and joint venture opportunities for the Company’s oil and gas assets. No assurances can be given that management will be successful.  

Recent Developments

Kern County Drilling Program: On July 18, 2017, the Company announced a new oil field discovery upon successful drilling of the Cattani-Rennie 47X-15 exploration well (“CR 47X”) in its Sunset Boulevard prospect in Kern County, California. The Company is currently conducting well tests on multiple zones. Results are expected in October 2017. The Company owns a 19.25% interest in the Sunset Boulevard prospect in Kern County field based on a 13.75% direct working interest, and a 5.5% indirect working interest through its 20% equity investment in Horizon Energy.

On August 15, 2017, the Company announced a second oil field discovery upon successful drilling of the Chardonnay 47X-35 exploration well (the “Chardonnay 47X”) at its Grapevine project in Kern County, California. The Company is currently conducting well tests, and expects to announce production results in October 2017. The Company owns an 8% indirect interest in the Grapevine project through its 20% equity investment in Horizon Energy.

Osage County Drilling Program:  On May 8, 2017, the Company announced the discovery of a new oil field on the Company's 106,500-acre concession in Osage County, Oklahoma (the “Osage Concession”).  The Company’s Chat #2-11, now known as the S. Blackland #2-11, successfully tested a seismically-delineated structure on the Company’s concession. The 30-day oil flow test indicates initial production rates of up to 35 BOE per day. 

On May 30, 2017, the Company announced a second oil discovery on its Osage Concession.  The 30-day oil flow test of the Red Fork 1-3 well, now known as the W. Blackland #1-3, indicates initial production rates of up to 71 BOE per day.

The Company recently identified 1,730 acres of structural closures highlighted in its existing 3D seismic, and confirmed as a result of the successful drilling of W. Blackland #1-3 and S. Blackland #2-11.  The Company does not expect to have any meaningful production until early 2018 following completion of its 2017 drilling program.  Currently, both the W. Blackland #1-3 and S. Blackland #2-11 wells are shut-in until late 2017 in order to build production facilities.

$2.0 Million Secured Note Financing. On June 13, 2017, the Company entered into a Securities Purchase Agreement (“Purchase Agreement”) with Petro Exploration Funding, LLC (“Funding Corp.”), pursuant to which the Company issued to Funding Corp. a senior secured promissory note to finance the Company’s working capital requirements, in the principal amount of $2.0 million (“Secured Note”). As additional consideration for the note financing, the Company issued to Funding Corp. (i) a warrant to purchase 840,336 shares of the Company’s common stock, $0.00001 par value, and (ii) an overriding royalty interest equal to 2% in all production from the Company’s interest in the Company’s concessions located in Osage County, Oklahoma, currently held by Spyglass pursuant to an Assignment of Overriding Royalty Interests (the “2017 Override”).

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The Secured Note accrues interest at a rate of 10% per annum, and matures on June 30, 2020. To secure the repayment of all amounts due under the terms of the Secured Note, the Company entered into a Security Agreement, pursuant to which the Company granted to Funding Corp. a security interest in all assets of the Company. The first interest payment will be due on June 1, 2018, and each six-month anniversary thereafter until the outstanding principal balance of the Secured Note is paid in full.

The warrant is exercisable immediately upon issuance, for an exercise price per share equal to $2.38 per share, and shall terminate, if not previously exercised, five years from the date of issuance. Scot Cohen, a member of the Company’s Board of Directors and a substantial stockholder of the Company, owns or controls 31.25% of Funding Corp.

Purchase of 2% Overriding Royalty Interest. On August 14, 2017, following a review of the Company’s capital requirements necessary to fund its 2017 development program, the Company’s independent directors consented to Scot Cohen’s purchase from various third parties who collectively held a 2% overriding royalty interest that originally burdened the Osage County, Oklahoma concession for $250,000 (the “Original Override”). Mr. Cohen agreed to sell the Original Override to the Company at the same price paid by him (plus market interest on his capital) upon a determination by the Company to finance the Osage County development plan on terms similar to the June 13, 2017 secured note financing.

2. Basis of Preparation

The accompanying unaudited interim consolidated financial statements are prepared in accordance with U.S. GAAP and include the accounts of the Company and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation. Non–controlling interest represents the minority equity investment in the Company’s subsidiaries, plus the minority investors’ share of the net operating results and other components of equity relating to the non–controlling interest.

These unaudited consolidated financial statements include the Company and the following subsidiaries:

Petro Spring, LLC, PO1, LLC, Petro River UK Limited, Horizon I Investments, LLC and MegaWest Energy USA Corp. and MegaWest Energy USA Corp.’s wholly owned subsidiaries:

MegaWest Energy Texas Corp.

MegaWest Energy Kentucky Corp.

MegaWest Energy Missouri Corp.

Also contained in the unaudited consolidated financial statements is the financial information of the Company’s 58.51% owned subsidiary, MegaWest Energy Kansas Corporation (“MegaWest”), which resulted from a transaction with Fortis Property Group, LLC, a Delaware limited liability company (“Fortis”) consummated on October 15, 2015 (the “MegaWest Transaction”). The MegaWest Transaction includes the Company’s contribution of its 50% interest in Bandolier Energy LLC.

The unaudited consolidated financial information furnished herein reflects all adjustments, consisting solely of normal recurring items, which in the opinion of management are necessary to fairly state the financial position of the Company and the results of its operations for the periods presented. This report should be read in conjunction with the Company’s consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended April 30, 2017 filed with the Securities and Exchange Commission (the “SEC”) on July 31, 2017. The Company assumes that the users of the interim financial information herein have read or have access to the audited financial statements for the preceding fiscal year and that the adequacy of additional disclosure needed for a fair presentation may be determined in that context. Accordingly, footnote disclosure, which would substantially duplicate the disclosure contained in the Company’s Form 10-K for the year ended April 30, 2017 has been omitted. The results of operations for the interim periods presented are not necessarily indicative of results for the entire year ending April 30, 2018.

3. Significant Accounting Policies

 (a) Use of Estimates:

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

The Company’s financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties, and timing and costs associated with its asset retirement obligations, as well as those related to the fair value of stock options, stock warrants and stock issued for services. While we believe that our estimates and assumptions used in preparation of the financial statements are appropriate, actual results could differ from those estimates.

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 (b) Cash and Cash Equivalents:

Cash and cash equivalents include all highly liquid monetary instruments with original maturities of three months or less when purchased. These investments are carried at cost, which approximates fair value. Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash deposits. The Company maintains its cash in institutions insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, the Company’s cash and cash equivalent balances may be uninsured or in amounts that exceed the FDIC insurance limits. At July 31, 2017, approximately $788,831 of the Company’s cash balances were uninsured. The Company has not experienced any loses on such accounts.

 (c) Receivables:

Receivables that management has the intent and ability to hold for the foreseeable future are reported in the balance sheet at outstanding principal adjusted for any charge-offs and the allowance for doubtful accounts. Losses from uncollectible receivables are accrued when both of the following conditions are met: (a) Information available before the financial statements are issued or are available to be issued indicates that it is probable that an asset has been impaired at the date of the financial statements, and (b) The amount of the loss can be reasonably estimated. These conditions may be considered in relation to individual receivables or in relation to groups of similar types of receivables. If the conditions are met, an accrual shall be made even though the particular receivables that are uncollectible may not be identifiable. The Company reviews individually each receivable for collectability and performs on-going credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current credit worthiness, as determined by the review of their current credit information; and determines the allowance for doubtful accounts based on historical write-off experience, customer specific facts and general economic conditions that may affect a client’s ability to pay. Bad debt expense is included in general and administrative expenses, if any.

Credit losses for receivables (uncollectible receivables), which may be for all or part of a particular receivable, shall be deducted from the allowance. The related receivable balance shall be charged off in the period in which the receivables are deemed uncollectible. Recoveries of receivables previously charged off shall be recorded when received. The Company charges off its account receivables against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

The allowance for doubtful accounts at July 31, 2017 and April 30, 2017 was $0.

 (d) Interest in Real Estate Rights:

Interest in real estate rights contributed by Fortis related to real properties that Fortis plans to sell within one year. Since these properties are contributed by Fortis, a related party, the rights are stated on balance sheet at the cost basis of Fortis.

 (e) Oil and Gas Operations:

Oil and Gas Properties: The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the costs of both successful and unsuccessful exploration and development activities are capitalized as oil and gas property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country, in which case a gain or loss would be recognized in the consolidated statements of operations. All of the Company’s oil and gas properties are located within the continental United States, its sole cost center.

Oil and gas properties may include costs that are excluded from costs being depleted. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and in process exploration drilling costs. All costs excluded are reviewed at least annually to determine if impairment has occurred.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate. For the three months ended July 31, 2017, the Company evaluated and recorded no impairment on these properties.

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Proved Oil and Gas Reserves: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. All of the Company’s oil and gas properties with proven reserves were impaired to the salvage value prior to the Bandolier transaction. The price used to establish economic producibility is the average price during the 12-month period preceding the end of the entity’s fiscal year and calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within such 12-month period. For the three months ended July 31, 2017, the Company did not record an impairment charge on its proved oil and gas properties.

Depletion, Depreciation and Amortization: Depletion, depreciation and amortization is provided using the unit-of-production method based upon estimates of proved oil and gas reserves with oil and gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is deducted from the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. 

In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by the Company’s geologists and engineers which require significant judgment, as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expenses. There have been no material changes in the methodology used by the Company in calculating depletion, depreciation and amortization of oil and gas properties under the full cost method during the three months ended July 31, 2017 and 2016.  

 (f) Investments – Cost Method and Equity Method:

Investments held in stock of entities other than subsidiaries, namely corporate joint ventures and other non-controlled entities usually are accounted for by one of three methods: (i) the fair value method, (ii) the equity method, or (iii) the cost method. The equity method tends to be most appropriate if an investment enables the investor to influence the operating or financial policies of the investee. The cost basis is utilized for investments that are less than 20% owned, and the Company does not exercise significant influence over the operating and financial policies of the investee. Under the cost method, investments are held at historical cost.

 (g) Fair Value of Financial Instruments:

The Company follows paragraph 825-10-50-10 of the FASB Accounting Standards Codification for disclosures about fair value of its financial instruments and paragraph 820-10-35-37 of the FASB Accounting Standards Codification (“Paragraph 820-10-35-37”) to measure the fair value of its financial instruments. Paragraph 820-10-35-37 establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, Paragraph 820-10-35-37 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by Paragraph 820-10-35-37 are described below:

Level 1	Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.
Level 2	Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3	Pricing inputs that are generally observable inputs and not corroborated by market data.

Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable.

The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

The carrying amount of the Company’s financial assets and liabilities, such as cash, prepaid expenses, and accounts payable and accrued liabilities approximate their fair value because of the short maturity of those instruments.

Transactions involving related parties cannot be presumed to be carried out on an arm’s-length basis, as the requisite conditions of competitive, free-market dealings may not exist. Representations about transactions with related parties, if made, shall not imply that the related party transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions unless such representations can be substantiated.

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 (h) Stock-Based Compensation:

Generally, all forms of stock-based compensation, including stock option grants, warrants, and restricted stock grants are measured at their fair value utilizing an option pricing model on the award’s grant date, based on the estimated number of awards that are ultimately expected to vest.

Under fair value recognition provisions, the Company recognizes equity–based compensation net of an estimated forfeiture rate and recognizes compensation cost only for those shares expected to vest over the requisite service period of the award.

The fair value of option award is estimated on the date of grant using the Black–Scholes option valuation model. The Black–Scholes option valuation model requires the development of assumptions that are input into the model. These assumptions are the expected stock volatility, the risk–free interest rate, the option’s expected life, the dividend yield on the underlying stock and the expected forfeiture rate. Expected volatility is calculated based on the historical volatility of the Company’s common stock over the expected option life and other appropriate factors. Risk–free interest rates are calculated based on continuously compounded risk–free rates for the appropriate term. The dividend yield is assumed to be zero as the Company has never paid or declared any cash dividends on its common stock and does not intend to pay dividends on the common stock in the foreseeable future. The expected forfeiture rate is estimated based on historical experience.

Determining the appropriate fair value model and calculating the fair value of equity–based payment awards requires the input of the subjective assumptions described above. The assumptions used in calculating the fair value of equity–based payment awards represent management’s best estimates, which involve inherent uncertainties and the application of management’s judgment. As a result, if factors change and the Company uses different assumptions, the equity–based compensation expense could be materially different in the future. In addition, the Company is required to estimate the expected forfeiture rate and recognize expense only for those shares expected to vest. If the actual forfeiture rate is materially different from our estimate, the equity–based compensation expense could be significantly different from what the Company has recorded in the current period. 

The Company determines the fair value of the stock–based payments to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.  If the fair value of the equity instruments issued is used, it is measured using the stock price and other measurement assumptions as of the earlier of either (1) the date at which a commitment for performance by the counterparty to earn the equity instruments is reached, or (2) the date at which the counterparty’s performance is complete.

The expenses resulting from stock-based compensation are recorded as general and administrative expenses in the consolidated statement of operations, depending on the nature of the services provided.

 (i) Income Taxes:

Income Tax Provision

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance to the extent management concludes it is more likely than not that the assets will not be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the statements of operations in the period that includes the enactment date.

The Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent (50%) likelihood of being realized upon ultimate settlement.

The estimated future tax effects of temporary differences between the tax basis of assets and liabilities are reported in the accompanying consolidated balance sheets, as well as tax credit carry-backs and carry-forwards. The Company periodically reviews the recoverability of deferred tax assets recorded on its consolidated balance sheets and provides valuation allowances as management deems necessary.

Management makes judgments as to the interpretation of the tax laws that might be challenged upon an audit and cause changes to previous estimates of tax liability. In addition, the Company operates within multiple taxing jurisdictions and is subject to audit in these jurisdictions. In management’s opinion, adequate provisions for income taxes have been made for all years. If actual taxable income by tax jurisdiction varies from estimates, additional allowances or reversals of reserves may be necessary.

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Uncertain Tax Positions

The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard, or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained.

At July 31, 2017 and April 30, 2017, the Company had approximately $3,640,928 and $3,442,724, respectively, of liabilities for uncertain tax positions. Interpretation of taxation rules relating to net operating loss utilization in real estate transactions give rise to uncertain positions. In connection with the uncertain tax position, there were no interest or penalties recorded as the position is expected but the tax returns are not yet due.

The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results.

The number of years with open tax audits varies depending on the tax jurisdiction. The Company’s major taxing jurisdictions include the United States (including applicable states).

 (j) Per Share Amounts:

Basic net income (loss) per common share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. For the three months ended July 31, 2017 and 2016, potentially dilutive securities were not included in the calculation of diluted net loss per share because to do so would be anti-dilutive.

The Company had the following common stock equivalents at July 31, 2017 and 2016:

	July 31, 2017	July 31, 2016
Stock Options	2,574,682	2,502,182
Stock Purchase Warrants	973,669	133,333
Total	3,548,351	2,635,515

 (k) Recent Accounting Pronouncements:

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard’s core principle (issued as ASU 2014-09 by the FASB), is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. These may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The new guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU 2014-09 by one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. This ASU is effective for public reporting companies for interim and annual periods beginning after December 15, 2017. The Company is currently evaluating its adoption method and the impact of the standard on its consolidated financial statements and has not yet determined the method by which the Company will adopt the standard in 2017.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing” (Topic 606). In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross verses Net)” (Topic 606). These amendments provide additional clarification and implementation guidance on the previously issued ASU 2014-09, “Revenue from Contracts with Customers”. The amendments in ASU 2016-10 provide clarifying guidance on materiality of performance obligations; evaluating distinct performance obligations; treatment of shipping and handling costs; and determining whether an entity's promise to grant a license provides a customer with either a right to use an entity's intellectual property or a right to access an entity's intellectual property. The amendments in ASU 2016-08 clarify how an entity should identify the specified good or service for the principal versus agent evaluation and how it should apply the control principle to certain types of arrangements. The adoption of ASU 2016-10 and ASU 2016-08 is to coincide with an entity's adoption of ASU 2014-09, which we intend to adopt for interim and annual reporting periods beginning after December 15, 2017. The Company is currently evaluating the impact of the new standard.

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In April 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation” (Topic 718). The FASB issued this update to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The updated guidance is effective for annual periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption of the update is permitted. The Company is currently evaluating the impact of the new standard.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 will make eight targeted changes to how cash receipts and cash payments are presented and classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017. The new standard will require adoption on a retrospective basis unless it is impracticable to apply, in which case it would be required to apply the amendments prospectively as of the earliest date practicable. The Company is currently in the process of evaluating the impact of ASU 2016-15 on its consolidated financial statements. 

The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations, or cash flows. 

 (k) Subsequent Events:

The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration. 

4. Accounts Receivable – Related Party

On October 15, 2015, the Company entered into a contribution agreement (the “Contribution Agreement”) with MegaWest and Fortis pursuant to which the Company and Fortis each agreed to contribute certain assets to MegaWest in exchange for shares of MegaWest common stock (“MegaWest Shares”) (the “MegaWest Transaction”). 

Upon execution of the Contribution Agreement, Fortis transferred its interest in 30 condominium units and the right to any profits and proceeds therefrom. For each of the three months ended July 31, 2017 and 2016, Fortis sold 1 condominium unit, and MegaWest recorded a net gain on interest in real estate rights of $271,490 and $300,639, respectively. As of July 31, 2017, the Company had an accounts receivable – related party in the amount of $1,146,673 related to interest in real estate rights of condominium units sold.

The accounts receivable and the Company’s interest in real estate reflected on the Company’s balance sheet are assets held by MegaWest, and are controlled by MegaWest’s board of directors, consisting of two members appointed by Fortis, and one by the Company. The relative composition of the board of directors of MegaWest shall continue as long as Fortis has an equity interest in MegaWest.

Proceeds from the amounts receivable from Fortis will not be available until such time as the Company has completed its evaluation of the Bandolier prospects. In this regard, the Contribution Agreement provided for a redetermination of the fair market value of the Bandolier Interest at any time following the six month anniversary after the execution thereof (the “Redetermination”),  Upon a Redetermination, which has not occurred as of September 14, 2017, but is anticipated prior to December 31, 2017, in the event there is a shortfall from the valuation ascribed to the Bandolier Interest at the time of the Redetermination, as compared to the value ascribed to the Bandolier Interest in the Contribution Agreement, the Company will be required to provide Fortis with a cash payment in an amount equal to the shortfall.  If the Company is unable to deliver to Fortis the cash payment required after the Redetermination, if any, the board of directors of MegaWest shall have the right to exercise certain remedies against the Company, including a right to foreclose on the Company’s entire equity in MegaWest, which equity interest has been pledged to Fortis under the terms of the Contribution Agreement.  In the event of foreclosure, the Bandolier Interest would revert back to the Company, and the Company would record a loss for the amount of the notes receivable, interest in real estate rights, accounts receivable – related party, and any accrued interest.

5. Notes Receivable – Related Party

Since December 2015, the Company has entered into ten promissory note agreements with Fortis with aggregate principal amounts of $26,344,883. The notes receivable bear interest at an annual rate of 3% and mature on December 31, 2017. As of July 31, 2017, and April 31, 2017, the outstanding balance of the notes receivable was $26,344,883 and $24,786,382, respectively.

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6. Interest in Real Estate Rights

As discussed in Note 5, MegaWest received an interest in real estate rights of 30 condominium units from Fortis pursuant to the MegaWest Transaction.  For the three months ended July 31, 2017, the Company recognized a net gain of $271,490 related to the sale of one condominium unit by Fortis.

The following table summarizes the activity for interest in real estate rights:

	Three Months Ended July 31, 2017
Balance at April 30, 2017	$309,860
Cost of sales – one condominium unit	(309,860)
Balance at July 31, 2017	$-

7. Oil and Gas Assets

The following table summarizes the activity of the oil and gas assets by project for the three months ended July 31, 2017:

	Oklahoma	Larne Basin	Other (1)	Total
Balance May 1, 2017	$1,232,192	$761,444	$100,000	$2,093,636
Additions	744,464	-	-	744,464
Disposals	-	-	-	-
Depreciation, depletion and amortization	(5,959)	-	-	(5,959)
Impairment of oil and gas assets	-	-	-	-
Balance July 31, 2017	$1,970,697	$761,444	$100,000	$2,832,141

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2017, and April 30, 2017, management concluded that impairment was not necessary as all other assets were carried at salvage value.

Kern County Project.  On March 4, 2016, the Company executed an Asset Purchase and Sale and Exploration Agreement to acquire a 13.75% working interest in certain oil and gas leases located in southern Kern County, California. Horizon Energy also purchased a 27.5% working interest in the project.

Under the terms of the agreement, the Company paid $108,333 to the sellers on the closing date, and is obligated to pay certain other costs and expenses after the closing date related to existing and new leases as more particularly set forth in the agreement. As of April 30, 2016, exploratory activity had not commenced and the $108,333 was recorded as prepaid oil and gas development costs on the consolidated balance sheet. In addition, the sellers are entitled to an overriding royalty interest in certain existing and new leases acquired after the closing date, and the Company is required to make certain other payments, each in amounts set forth in the agreement.

Acquisition of Interest in Larne Basin.  On January 19, 2016, Petro River UK Limited, ("Petro UK"), a wholly owned subsidiary of the Company, entered into a Farmout Agreement to acquire a 9% interest in Petroleum License PL 1/10 and P2123 (the “Larne Licenses”) located in the Larne Basin in Northern Ireland (the "Larne Transaction").  The two Larne Licenses, one onshore and one offshore, together encompass approximately 130,000 acres covering the large majority of the prospective Larne Basin.  The other parties to the Farmout Agreement are Southwestern Resources Ltd, a wholly owned subsidiary of Horizon Energy, which will acquire a 16% interest, and Brigantes Energy Limited, which will retain a 10% interest.  Third parties will own the remaining 65% interest.

Under the terms of the Farmout Agreement, Petro UK deposited approximately $735,000 into an escrow agreement (“Escrow Agreement”), which amount represented Petro UK's obligation to fund the total projected cost to drill the first well under the terms of the Farmout Agreement. As of July 31, 2016, development of the first well had not commenced and the escrow payment was recorded as prepaid oil and gas development costs on the consolidated balance sheet.The total deposited amount to fund the cost to drill the first well is approximately $6,159,452, based on an exchange rate of one British Pound for 1.44 U.S. Dollars. Petro UK was and will continue to be responsible for its pro-rata costs of additional wells drilled under the Farmout Agreement. Drilling of the first well was completed in June 2016.

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Oklahoma Properties. During the three months ended July 31, 2017, the Company paid approximately $739,500 and $5,000 for proven and unproven oil and gas assets, respectively.

Divestiture of Kansas Properties. On December 23, 2015, Petro River Oil, LLC (“Petro LLC”), a wholly owned subsidiary of MegaWest, divested various interests in oil and gas leases, wells, records, data and related personal property located along the Mississippi Lime play in the state of Kansas, which assets were acquired by Petro LLC in 2012. In connection with the divestiture, the assignee and purchaser of the interests agreed to pay outstanding liabilities, including unpaid taxes, and assume certain responsibilities to plug any abandoned wells. No cash consideration was paid for the interests.  The Company recorded a loss of $7,519,460 in connection with the divestiture of these oil and gas properties, representing the $7,727,287 oil and gas assets book value, partially offset by the asset retirement obligation liability. MegaWest is a 58.51% owned subsidiary of the Company following consummation of the MegaWest Transaction, defined above.

Impairment of Oil & Gas Properties. As of July 31, 2017, the Company assessed its oil and gas assets for impairment and did not recognized a charge related to its oil and gas property. As of April 30, 2017, the Company assessed its oil and gas assets for impairment and recognized a charge of $20,942 related to the Oklahoma oil and gas property.

8. Asset Retirement Obligations

The total future asset retirement obligations were estimated based on the Company’s ownership interest in all wells and facilities, the estimated legal obligations required to retire, dismantle, abandon and reclaim the wells and facilities and the estimated timing of such payments. The Company estimated the present value of its asset retirement obligations at both July 31, 2017 and April 30, 2017, based on a future undiscounted liability of $648,848 and $573,069, respectively. These costs are expected to be incurred within one to 24 years. A credit-adjusted risk-free discount rate of 10% and an inflation rate of 2% were used to calculate the present value.

Changes to the asset retirement obligations were as follows:

	Three Months Ended July 31, 2017	Three Months Ended July 31, 2016
Balance, beginning of period	$558,696	$763,062
Additions	7,500	-
Disposals	-	(216,580
Accretion	2,971	4,207
	569,167	550,689
Less: Current portion for cash flows expected to be incurred within one year	(406,403)	(406,403)
Long-term portion, end of period	$162,764	$144,286

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Expected timing of asset retirement obligations:

Year Ending April 30,
2018 (remainder of year)	$406,403
2019	-
2020	-
2021	-
2022	-
Thereafter	242,445
Subtotal	648,848
Effect of discount	(79,681)
Total	$569,167

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9. Related Party Transactions

Employment Agreements

On October 30, 2015, Mr. Stephen Brunner joined the Company as President.  Mr. Brunner has been tasked with making oil and gas related decisions and executing the Company’s growth strategy. Under the terms of the contract, Mr. Brunner receives a base salary of $10,000 per month. Mr. Brunner was also granted 53,244 stock options. He also has the right to purchase an additional 1.75% of the Company’s common stock subject to shareholder approval on the increase of the current stock option plan and achieving pre-defined target objectives.

The Company computed the fair value of the grant as of the date of grant utilizing a Black-Scholes option-pricing model using the following assumptions: common share value based on the fair value of the Company’s common stock as quoted on the Over the Counter Bulletin Board, $1.78; exercise price of $2.00; expected volatility of 171%; and a discount rate of 2.16%. The grant date fair value of the award was $89,525. For the three months ended July 31, 2017 and 2016, the Company expensed $6,101 and $6,101, respectively, to general and administrative expenses. 

MegaWest Transaction

On October 15, 2015, the Company entered into the Contribution Agreement with MegaWest and Fortis, pursuant to which the Company and Fortis each agreed to contribute certain assets to MegaWest in exchange for shares of MegaWest common stock. See Note 5 above.

Accounts Receivable - Related Party

As discussed in Note 5 above, on October 15, 2015, the Company entered into the Contribution Agreement with MegaWest and Fortis pursuant to which the Company and Fortis each agreed to assign certain assets to MegaWest in exchange for the MegaWest Shares.

Upon execution of the Contribution Agreement, Fortis transferred certain indirect interests held in 30 condominium units and the rights to any profits and proceeds therefrom, with its basis of $15,544,382, to MegaWest. As of July 31, 2017 and April 30, 2017, the Company had an accounts receivable – related party in the amount of $1,146,673 and $2,123,175, respectively, which was due from Fortis for the profits belonging to MegaWest. See Note 5 above.  

Notes Receivable – Related Party

As discussed in Note 6, the Company entered into ten promissory note agreements with Fortis, with total principal amount of $26,344,883 as of July 31, 2017. The notes receivable bear interest at an annual interest rate of 3% and mature on December 31, 2017. For the three months ended July 31, 2017, the Company recorded $194,599 of interest income on the notes receivable. As of July 31, 2017, and April 30, 2017, the outstanding balance of the notes receivable was $26,344,883 and $24,786,382, respectively.

Notes Payable – Related Party

On December 1, 2015, the Company issued a non-recourse promissory note, in the principal amount of $750,000 to Horizon Investments (“Note A”), the proceeds of which were to be used for working capital purposes. Interest on Note A was due upon the earlier to occur of closing of the Horizon Transaction, or December 31, 2016. Amounts due under the terms of Note A accrued interest at an annual rate equal to one half of one percent.

On December 7, 2015, the Company entered into the Horizon Transaction, pursuant to which the Company executed a purchase agreement to acquire Horizon Investments in an all-stock deal. See Note 4. Mr. Scot Cohen, the Company’s Executive Chairman, is the sole Manager of Horizon Investments. In addition, Mr. Cohen owns a 9.2% membership interest in Horizon Investments. Horizon Investments owns a 20% interest in Horizon Energy Partners.  Mr. Cohen owns a 2.8% membership interest in Horizon Energy Partners.

On January 13, 2016, the Company issued a second non-recourse promissory note in the principal amount of $750,000 (“Note B”) to Horizon Investments. All of the proceeds from Note B were used to fund Petro UK's obligations under the terms of the Farmout Agreement, and were deposited into the Escrow Agreement. The principal and all accrued and unpaid interest on Note B was due upon the earlier to occur of closing of the transactions contemplated under the terms of the Purchase Agreement. Amounts due under the terms of Note B accrued interest at an annual rate equal to one half of one percent.

On April 7, 2016, the Company issued a third non-recourse promissory note in the principal amount of $100,000 (“Note C”) to Horizon Investments. All of the proceeds from Note C were used to fund working capital requirements. The principal and all accrued and unpaid interest on Note C was due upon the earlier to occur of closing of the transactions contemplated under the terms of the Purchase Agreement. Amounts due under the terms of Note C accrued interest at an annual rate equal to one half of one percent.

Upon consummation of the Horizon Transaction on May 3, 2016, each of Note A, Note B and Note C were paid off in full.

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$2.0 Million Secured Note Financing

Scot Cohen, a member of the Company’s Board of Directors and a substantial stockholder of the Company, owns or controls 31.25% of Funding Corp., the holder of the Secured Note issued by the Company in June 2017 in the principal amount of $2.0 million. The Secured Note accrues interest at a rate of 10% per annum, and matures on June 30, 2020. (See Note 1). The Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

Pursuant to the financing agreement, the Company issued to Funding Corp. a warrant to purchase 840,336 shares of the Company’s common stock. Upon issuance of the note, the Company valued the warrants at the grant date share price of $2.38 and recorded $952,056 to debt discount on the consolidated balance sheet. The debt discount is amortized over the earlier of (i) the term of the debt or (ii) conversion of the debt, using the effective interest method. The amortization of debt discount is included as a component of interest expense in the consolidated statements of operations. There was unamortized debt discount of $914,678 as of July 31, 2017. During the three months ended July 31, 2017 and 2016, the Company recorded amortization of debt discount totaling $37,378 and $0, respectively. See Note 10 for the assumptions and inputs utilized to value the warrants granted.

As of July 31, 2017, the outstanding balance, net of debt discount, and accrued interest on the notes due to the lender was $1,085,322 and $24,476, respectively. 

As additional consideration for the purchase of the Secured Note, the Company issued to Funding Corp. the 2017 Override, which provided Funding Corp. with an overriding royalty interest equal to 2% in all production from the Company’s interest in the Company’s concessions located in Osage County, Oklahoma, currently held by Spyglass.

Purchase of 2% Overriding Royalty

On August 14, 2017, following a review of the Company’s capital requirements necessary to fund its 2017 development program, the Company’s independent directors consented to Scot Cohen’s purchase from various third parties who collectively held a 2% overriding royalty interest that originally burdened the Osage County, Oklahoma concession for $250,000 (the “Original Override”). Mr. Cohen agreed to sell the Original Override to the Company at the same price paid by him (plus market interest on his capital) upon a determination by the Company to finance the Osage County development plan on terms similar to the June 13, 2017 secured note financing.

10. Equity

As of July 31, 2017 and April 30, 2017, the Company had 5,000,000 shares of preferred stock, par value $0.00001 per share, authorized. As of July 31, 2017 and April 30, 2017, the Company had 29,500 shares of Series B Preferred Stock, par value $0.00001 per share (“Series B Preferred”), authorized. No Series B Preferred shares are currently issued or outstanding, and no other series of preferred stock have been designated. 

As of July 31, 2017 and April 30, 2017, the Company had 150,000,000 shares of common stock, par value $0.00001 per share, authorized. During the three months ended July 31, 2017, the Company issued 12,222 shares of common stock related to a cashless exercise of 25,000 options. There were 15,840,143 and 15,827,921 shares of common stock issued and outstanding as of July 31, 2017 and April 30, 2017, respectively. 

Options

The following table summarizes information about the options changes of options for the period from April 30, 2017 to July 31, 2017 and options outstanding and exercisable at July 31, 2017:

	Options	Weighted Average Exercise Prices
Outstanding April 30, 2017	2,599,682	$2.13
Exercisable – April 30, 2017	1,954,735	2.35
Granted	-
Exercised	(25,000)	1.38
Forfeited/Cancelled	-
Outstanding – July 31, 2017	2,574,682	2.14
Exercisable – July 31, 2017	2,169,277	$2.25
Outstanding – Aggregate Intrinsic Value		$1,717,333
Exercisable – Aggregate Intrinsic Value		$1,412,799

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The following table summarizes information about the options outstanding and exercisable at July 31, 2017:

Exercise Price	Options Outstanding	Weighted Avg. Life Remaining (years)	Options Exercisable	Weighted Average Exercise Price
$1.38	1,840,958	9.54	1,509,503	$1.38
$1.98	5,000	9.27	4,950	$1.98
$2.00	457,402	8.25	392,781	$2.00
$2.87	65,334	8.25	64,611	$2.87
$3.00	51,001	9.91	42,445	$3.00
$3.39	12,000	8.89	12,000	$3.39
$6.00	10,000	8.00	10,000	$6.00
$12.00	132,987	6.73	132,987	$12.00
	2,574,682		2,169,277

The aggregate intrinsic value of the outstanding options was $1,717,333.

During the three months ended July 31, 2017 and 2016, the Company expensed $529,332 and $1,150,197, respectively, related to the vesting of outstanding options to general and administrative expense for stock-based compensation pursuant to employment and consulting agreements. 

As of July 31, 2017, the Company has approximately $972,397 in unrecognized stock-based compensation expense related to unvested options, which will be amortized over a weighted average exercise period of approximately 3.00 years.

Warrants

The fair value of the 840,336 warrants granted in conjunction with the $2.0 Million Secured Note (as discussed in Note 9) were estimated on the date of grant using the Black-Scholes option-pricing model.

The assumptions used for the warrants granted during the three months ended July 31, 2017 are as follows:

	June 30, 2017
Exercise price	$2.38
Expected dividends	0%
Expected volatility	169.63%
Risk free interest rate	1.49%
Expected life of warrant	3 years

The following is a summary of the Company’s warrant activity:

	Number of Warrants	Weighted Average Exercise Price	Weighted Average Life Remaining
Outstanding and exercisable – April 30, 2017	133,333	$50.00	2.83
Forfeited	-	-	-
Granted	840,336	2.05	2.48
Outstanding and exercisable – July 31, 2017	973,669	8.90	2.84

The aggregate intrinsic value of the outstanding warrants was $0.

11. Non-Controlling Interest

For the three months ended July 31, 2017, the changes in the Company’s non–controlling interest were as follows:

	Bandolier	Fortis	Total
Non–controlling interest at April 30, 2017	$(699,873)	$13,310,343	$12,610,470
Contribution of cash by non-controlling interest holders	-	-	-
Non–controlling interest share of income (losses)	(36,574)	111,145	74,571
Non–controlling interest at July 31, 2017	$(736,447)	$13,421,488	$12,685,041

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12. Contingency and Contractual Obligations

Pending Litigation.

(a) In January 2010, the Company experienced a flood in its Calgary office premises as a result of a broken water pipe. There was significant damage to the premises rendering them unusable until the landlord had completed remediation. Pursuant to the lease contract, the Company asserted that rent should be abated during the remediation process and accordingly, the Company did not pay any rent after December 2009. During the remediation process, the Company engaged an independent environmental testing company to test for air quality and for the existence of other potentially hazardous conditions. The testing revealed the existence of potentially hazardous mold and the consultant provided specific written instructions for the effective remediation of the premises. During the remediation process, the landlord did not follow the consultant’s instructions and correct the potentially hazardous mold situation and subsequently in June 2010 gave notice and declared the premises to be ready for occupancy. The Company re-engaged the consultant to re-test the premises and the testing results again revealed the presence of potentially hazardous mold. The Company determined that the premises were not fit for re-occupancy and considered the landlord to be in default of the lease. The Landlord subsequently terminated the lease.

On January 30, 2014, the landlord filed a Statement of Claim against the Company for rental arrears in the amount aggregating CAD $759,000 (approximately USD $625,000 as of September 13, 2017). The Company filed a defense and on October 20, 2014, it filed a summary judgment application stating that the landlord’s claim is barred as it was commenced outside the 2-year statute of limitation period under the Alberta Limitations Act. The landlord subsequently filed a cross-application to amend its Statement of Claim to add a claim for loss of prospective rent in an amount of CAD $665,000 (approximately USD $548,000 as of September 13, 2017). The applications were heard on June 25, 2015 and the court allowed both the Company’s summary judgment application and the landlord’s amendment application.  Both of these orders were appealed though two levels of the Alberta courts and the appeals were dismissed at both levels. The net effect is that the landlord's claim for loss of prospective rent is to proceed.

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Commission”) that the Company was not in compliance with regulations promulgated by the Commission. The Company was therefore deemed to have lost its corporate privileges within the State of Texas and as a result, all wells within the state would have to be plugged. The Commission therefore collected $25,000 from the Company, which was originally deposited with the Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Commission also reserved its right to separately seek any remedies against the Company resulting from its noncompliance.

(c) On August 11, 2014, Martha Donelson and John Friend amended their complaint in an existing lawsuit by filing a class action complaint styled: Martha Donelson and John Friend, et al. v. United States of America, Department of the Interior, Bureau of Indian Affairs and Devon Energy Production, LP, et al., Case No. 14-CV-316-JHP-TLW, United States District Court for the Northern District of Oklahoma (the “Proceeding”).  The plaintiffs added as defendants twenty-seven (27) specifically named operators, including Spyglass, as well as all Osage County lessees and operators who have obtained a concession agreement, lease or drilling permit approved by the Bureau of Indian Affairs (“BIA”) in Osage County allegedly in violation of National Environmental Policy Act (“NEPA”).  Plaintiffs seek a declaratory judgment that the BIA improperly approved oil and gas leases, concession agreements and drilling permits prior to August 12, 2014, without satisfying the BIA’s obligations under federal regulations or NEPA, and seek a determination that such oil and gas leases, concession agreements and drilling permits are void ab initio.  Plaintiffs are seeking damages against the defendants for alleged nuisance, trespass, negligence and unjust enrichment.  The potential consequences of such complaint could jeopardize the corresponding leases.

On October 7, 2014, Spyglass, along with other defendants, filed a Motion to Dismiss the August 11, 2014 Amended Complaint on various procedural and legal grounds. Following the significant briefing, the Court, on March 31, 2016, granted the Motion to Dismiss as to all defendants and entered a judgment in favor of the defendants against the plaintiffs. On April 14, 2016, Spyglass with the other defendants, filed a Motion seeking its attorneys’ fees and costs. The motion remains pending. On April 28, 2016, the plaintiffs filed three motions: a Motion to Amend or Alter the Judgment; a Motion to Amend the Complaint; and a Motion to Vacate Order. On November 23, 2016, the Court denied all three of Plaintiffs’ motions.  On December 6, 2016, Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals.  That appeal is pending as of the effective date of this response. There is no specific timeline by which the Court of Appeals must render a ruling. Spyglass intends to continue to vigorously defend its interest in this matter. 

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(d) MegaWest Energy Missouri Corp. (“MegaWest Missouri”), a wholly owned subsidiary of the Company, is involved in two cases related to oil leases in West Central, Missouri.  The first case (James Long and Jodeane Long v. MegaWest Energy Missouri and Petro River Oil Corp., case number 13B4-CV00019) is a case for unlawful detainer, pursuant to which the plaintiffs contend that MegaWest Missouri oil and gas lease has expired and MegaWest Missouri is unlawfully possessing the plaintiffs’ real property by asserting that the leases remain in effect.  The case was originally filed in Vernon County, Missouri on September 20, 2013.  MegaWest Missouri filed an Answer and Counterclaims on November 26, 2013 and the plaintiffs filed a motion to dismiss the counterclaims. MegaWest Missouri filed a motion for Change of Judge and Change of Venue and the case was transferred to Barton County.  The court granted the motion to dismiss the counterclaims on February 3, 2014.  As to the other allegations in the complaint, the matter is still pending.

MegaWest Missouri filed a second case on October 14, 2014 (MegaWest Energy Missouri Corp. v. James Long, Jodeane Long, and Arrow Mines LLC, case number 14VE-CV00599).  This case is pending in Vernon County, Missouri.  Although the two cases are separate, they are interrelated.  In the Vernon County case, MegaWest Missouri has made claims for: (1) replevin for personal property; (2) conversion of personal property; (3) breach of the covenant of quiet enjoyment regarding the lease; (4) constructive eviction of the lease; (5) breach of fiduciary obligation against James Long; (6) declaratory judgment that the oil and gas lease did not terminate; and (7) injunctive relief to enjoin the action pending in Barton County, Missouri.  The plaintiffs filed a motion to dismiss on November 4, 2014, and Arrow Mines, LLC filed a motion to dismiss on November 13, 2014.  Both motions remain pending, and MegaWest Missouri will file an opposition to the motions in the near future. 

The Company is from time to time involved in legal proceedings in the ordinary course of business. It does not believe that any of these claims and proceedings against it is likely to have, individually or in the aggregate, a material adverse effect on its financial condition or results of operations.

Redetermination of Bandolier Interest.

In connection with the Contribution Agreement, entered into by and between the Company, MegaWest and Fortis (see Note 5), the parties agreed to the Redetermination of the fair market value of the Bandolier Interest at any time following the six-month anniversary after the execution thereof.  Upon a Redetermination, which has not occurred as of September 14, 2017, but is anticipated prior to December 31, 2017, in the event there is a shortfall from the valuation ascribed to the Bandolier Interest at the time of the Redetermination, as compared to the value ascribed to the Bandolier Interest in the Contribution Agreement, the Company will be required to provide Fortis with a cash payment in an amount equal to the shortfall.  If the Company is unable to deliver to Fortis the cash payment required after the Redetermination, if any, the board of directors of MegaWest shall have the right to exercise certain remedies against the Company, including a right to foreclose on the Company’s entire equity in MegaWest, which equity interest has been pledged to Fortis under the terms of the Contribution Agreement.  In the event of foreclosure, the Bandolier Interest would revert back to the Company, and the Company would record a loss for the amount of the notes receivable, interest in real estate rights, accounts receivable – related party, and any accrued interest.

13. Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were available to be issued. Based on this evaluation, the Company has identified no reportable subsequent events other than those disclosed below or elsewhere in these financials.

In August 2017, the Company issued 2,923 shares of common stock related to a cashless exercise of 10,000 options.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Except as otherwise indicated by the context, references in this Quarterly Report to “we”, “us”, “our” or the “Company” are to the consolidated businesses of Petro River Oil Corp. and its wholly-owned direct and indirect subsidiaries and majority-owned subsidiaries, except that references to “our common stock” or “our capital stock” or similar terms refer to the common stock, par value $0.00001 per share, of Petro River Oil Corp., a Delaware corporation (the “Company”).

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is designed to provide information that is supplemental to, and should be read together with, the Company’s consolidated financial statements and the accompanying notes contained in this Quarterly Report. Information in this Item 2 is intended to assist the reader in obtaining an understanding of the consolidated financial statements, the changes in certain key items in those financial statements from quarter to quarter, the primary factors that accounted for those changes, and any known trends or uncertainties that the Company is aware of that may have a material effect on the Company’s future performance, as well as how certain accounting principles affect the consolidated financial statements. This includes discussion of (i) Liquidity, (ii) Capital Resources, (iii) Results of Operations, and (iv) Off-Balance Sheet Arrangements, and any other information that would be necessary to an understanding of the company’s financial condition, changes in financial condition and results of operations.

Forward Looking Statements

The following is management’s discussion and analysis of certain significant factors which have affected our financial position and operating results during the periods included in the accompanying consolidated financial statements, as well as information relating to the plans of our current management and should be read in conjunction with the accompanying financial statements and their related notes included in this Report. References in this section to “we,” “us,” “our,” or the “Company” are to the consolidated business of Petro River Oil Corp. and its wholly owned and majority owned subsidiaries.

This Report contains forward-looking statements. Generally, the words “believes,” “anticipates,” “may,” “will,” “should,” “expects,” “intends,” “estimates,” “continues,” and similar expressions or the negative thereof or comparable terminology are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, including the matters set forth in this Report or other reports or documents we file with the Securities and Exchange Commission (“SEC”) from time to time, which could cause actual results or outcomes to differ materially from those projected. Undue reliance should not be placed on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to update these forward-looking statements.

The following discussion of our financial condition and results of operations is based upon and should be read in conjunction with our consolidated financial statements and their related notes included in this Quarterly Report and our Annual Report on Form 10-K filed with the SEC on July 31, 2017 for the year ended April 30, 2017.

Business Overview

The Company is an independent energy company focused on the exploration and development of conventional oil and gas assets with low discovery and development costs. The Company is currently focused on moving forward with drilling wells on several of its properties owned directly and indirectly through its interest in Horizon Energy Partners, LLC (“Horizon Energy”), as well as taking advantage of the relative depressed market in oil prices to enter highly prospective plays with Horizon Energy and other industry-leading partners. Diversification over a number of projects, each with low initial capital expenditures and strong risk reward characteristics, reduces risk and provides cross-functional exposure to a number of attractive risk adjusted opportunities.

The Company’s core holdings are in the Mid-Continent Region in Oklahoma and in Kern County, California.  Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company now has exposure to a portfolio of several domestic and international oil and gas assets consisting of highly prospective conventional plays diversified across project type, geographic location and risk profile, as well as access to a broad network of industry leaders from Horizon Investment’s 20% interest in Horizon Energy.  Horizon Energy is an oil and gas exploration and development company owned and managed by former senior oil and gas executives.  It has a portfolio of domestic and international assets, including two assets located in the United Kingdom, adjacent to the giant Wytch Farm oil field, the largest onshore oil field in Western Europe.  Other projects include the proposed redevelopment of a large oil field in Kern County, California and the development of an additional recent discovery in Kern County.  Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

The execution of our business plan is dependent on obtaining necessary working capital.  While no assurances can be given, in the event management is able to obtain additional working capital, we plan to acquire high-quality oil and gas properties, primarily proved producing and proved undeveloped reserves. We also intend to explore low-risk development drilling and work-over opportunities.   Management is also exploring farm in and joint venture opportunities for our oil and gas assets.

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Recent Developments

Kern County Drilling Program: On July 18, 2017, the Company announced a new oil field discovery upon successful drilling of the Cattani-Rennie 47X-15 exploration well (“CR 47X”) in its Sunset Boulevard prospect in Kern County, California. The Company is currently conducting well tests on multiple zones. Results are expected in October 2017. The Company owns a 19.25% interest in the Sunset Boulevard prospect in Kern County field based on a 13.75% direct working interest, and a 5.5% indirect working interest through its 20% equity investment in Horizon Energy.

On August 15, 2017, the Company announced a second oil field discovery upon successful drilling of the Chardonnay 47X-35 exploration well (the “Chardonnay 47X”) at its Grapevine project in Kern County, California. The Company is currently conducting well tests, and expects to announce production results in October 2017. The Company owns an 8% indirect interest in the Grapevine project through its 20% equity investment in Horizon Energy.

Osage County Drilling Program:  On May 8, 2017, the Company announced the discovery of a new oil field on the Company's 106,500-acre concession in Osage County, Oklahoma (the “Osage Concession”).  The Company’s Chat #2-11, now known as the S. Blackland #2-11, successfully tested a seismically-delineated structure on the Company’s concession. The estimated ultimate recovery (“EUR”) per well is up to 63,000 barrels of oil equivalent (“BOE”). The 30-day oil flow test indicates initial production rates of up to 35 BOE per day. 

On May 30, 2017, the Company announced a second oil discovery on its Osage Concession.  The 30-day oil flow test of the Red Fork 1-3, now known as the W. Blackland #1-3, indicates initial production rates of up to 71 BOE per day, suggesting an EUR per well of 105,000 BOE.   Given the 250-acre size of this second structure, we anticipate drilling as many as eight offset wells before the end of 2017, which can produce a total of up to 945,000 BOE over the life of the field.  Each well is highly profitable at current oil prices with drilling and completion costs of approximately $200,000 and low lease operating expenses.

The Company expects to announce complete development plans for both of its S. Blackland and W. Blackland oilfields by October 2017.  In addition, the Company will also announce further exploration opportunities in its Osage Concession with a potential to prove up to 4,300,000 BOE (based on 20 acre well spacing) from the recently identified 1,730 acres of structural closures highlighted in its existing 3D seismic, and confirmed as a result of the successful drilling of W. Blackland #1-3 and S. Blackland #2-11.  The Company does not expect to have any meaningful production until early 2018 following completion of its 2017 drilling program.  Currently, both the W. Blackland #1-3 and S. Blackland #2-11 are shut-in until late 2017 in order to build production facilities.

The Company’s Osage County drilling program is the result of a Joint Exploration and Development Agreement (the “Exploration Agreement”), dated August 19, 2016, between Spyglass, a wholly owned subsidiary of Bandolier, Phoenix 2016, LLC (“Phoenix”) and Mackey Consulting & Leasing, LLC (“Mackey”). Pursuant to the Exploration Agreement, Phoenix and Mackey operates and provides certain services, including obtaining permits and providing technical services, at cost, in connection with a Phase I Development Program as agreed to by the parties (the “Phase I Program”).  Phoenix and Mackey shall earn a 25% working interest on all wells drilled in the Phase I Program.  Following success and completion of the Phase I Program, Phoenix and Mackey shall earn a 25% working interest in the Osage County, Oklahoma Concession held by Spyglass. Under the Exploration Agreement, Bandolier has agreed commit up to $2.1 million towards costs of the Phase I Program, at its sole discretion.

$2.0 Million Secured Note Financing. On June 13, 2017, the Company entered into a Securities Purchase Agreement (“Purchase Agreement”) with Petro Exploration Funding, LLC (“Funding Corp.”), pursuant to which the Company issued to Funding Corp. a senior secured promissory note to finance the Company’s working capital requirements, in the principal amount of $2.0 million (“Secured Note”). As additional consideration for the note financing, the Company issued to Funding Corp. (i) a warrant to purchase 840,336 shares of the Company’s common stock, $0.00001 par value, and (ii) an overriding royalty interest equal to 2% in all production from the Company’s interest in the Company’s concessions located in Osage County, Oklahoma, currently held by Spyglass pursuant to an Assignment of Overriding Royalty Interests (the “2017 Override”).

The Secured Note accrues interest at a rate of 10% per annum, and matures on June 30, 2020. To secure the repayment of all amounts due under the terms of the Secured Note, the Company entered into a Security Agreement, pursuant to which the Company granted to Funding Corp. a security interest in all assets of the Company. The first interest payment will be due on June 1, 2018 and each six-month anniversary thereafter until the outstanding principal balance of the Secured Note is paid in full.

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The warrant is exercisable immediately upon issuance, for an exercise price per share equal to $2.38 per share, and shall terminate, if not previously exercised, five years from the date of issuance.

Scot Cohen, a member of the Company’s Board of Directors and a substantial stockholder of the Company, owns or controls 31.25% of Funding Corp.

On August 14, 2017, following a review of the Company’s capital requirements necessary to fund its 2017 development program, the Company’s independent directors consented to Scot Cohen’s purchase from various third parties who collectively held a 2% overriding royalty interest that originally burdened the Osage County, Oklahoma concession for $250,000. Mr. Cohen agreed to sell this 2% overriding royalty to the Company at the same price paid by him (plus market interest on his capital) upon a determination by the Company to finance the Osage County development plan on terms similar to the June 13, 2017 secured note financing.  

Critical Accounting Policies and Estimates

The Company’s significant accounting policies are described in Note 3 to the annual consolidated financial statements for the year ended April 30, 2017 and 2015 on Form 10-K filed with the SEC on July 31, 2017 for the year ended April 30, 2017.

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. These consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States (“US GAAP”), which requires us to make estimates and assumptions that affect the reported amounts of our assets and liabilities and revenues and expenses, to disclose contingent assets and liabilities on the date of the consolidated financial statements, and to disclose the reported amounts of revenues and expenses incurred during the financial reporting period. The most significant estimates and assumptions include the valuation of accounts receivable, and the useful lives and impairment of property and equipment, goodwill and intangible assets, the valuation of deferred tax assets and inventories and the provision for income taxes. We continue to evaluate these estimates and assumptions that we believe to be reasonable under the circumstances. We rely on these evaluations as the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Since the use of estimates is an integral component of the financial reporting process, actual results could differ from those estimates. Some of our accounting policies require higher degrees of judgment than others in their application. We believe critical accounting policies as disclosed in this Form 10-Q reflect the more significant judgments and estimates used in preparation of our consolidated financial statements. We believe there have been no material changes to our critical accounting policies and estimates.

The following critical accounting policies rely upon assumptions and estimates and were used in the preparation of our consolidated financial statements:

Oil and Gas Operations

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to exploration and development of oil and gas reserves are capitalized. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities, however, are expensed in the period incurred. Costs are capitalized on a country-by-country basis. To date, there has only been one cost center, the United States.

The present value of estimated future net cash flows is computed by applying the average first-day-of-the-month prices during the previous twelve-month period of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year-end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Prior to December 31, 2009, prices and costs used to calculate future net cash flows were those as of the end of the appropriate quarterly period.

Following the discovery of reserves and the commencement of production, the Company will compute depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Unproved properties are assessed for impairment annually. Significant properties are assessed individually.

The Company assesses all items classified as unproved property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: land relinquishment; intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the related exploration costs incurred are transferred to the full cost pool and are then subject to depletion and the ceiling limitations on development oil and natural gas expenditures.

Proceeds from the sale of oil and gas assets are applied against capitalized costs, with no gain or loss recognized, unless a sale would alter the rate of depletion and depreciation by 25 percent or more.

Significant changes in these factors could reduce our estimates of future net proceeds and accordingly could result in an impairment of our oil and gas assets. Management will perform annual assessments of the carrying amounts of its oil and gas assets as additional data from ongoing exploration activities becomes available.

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Interest in Real Estate Rights

Interest in real estate rights, previously identified as “Real estate - held for sale” in our unaudited consolidated balance sheets are related to real estate currently held by Fortis, who intends to sell these properties within the next 12 months. Fortis contributed profit realized from future sale of these properties to MegaWest, pursuant to the terms and conditions of the Contribution Agreement, as a part of the MegaWest Transaction. As we do not know the price at which the real estate will be sold, the rights are stated on the consolidated balance sheet as of July 31, 2017 and April 30, 2017 at the cost basis realized by Fortis.

Income Taxes

The Company uses the asset and liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and income tax carrying amounts of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company reviews deferred tax assets for a valuation allowance based upon whether it is more likely than not that the deferred tax asset will be fully realized. A valuation allowance, if necessary, is provided against deferred tax assets, based upon management’s assessment as to their realization.

Uncertain Tax Positions

The Company evaluates uncertain tax positions pursuant to ASC Topic 740-10-25 “Accounting for Uncertainty in Income Taxes,” which allows companies to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard, or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained.

At July 31, 2017 and April 30, 2017, the Company has approximately $3,640,928 and $3,442,724, respectively, of liabilities for uncertain tax positions. Interpretation of taxation rules relating to net operating loss utilization in real estate transactions give rise to uncertain positions. In connection with the uncertain tax position, there was no interest or penalties recorded as the position is expected but the tax returns are not yet due.

The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results.

The number of years with open tax audits varies depending on the tax jurisdiction. The Company’s major taxing jurisdictions include the United States (including applicable states).

NEW ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard’s core principle (issued as ASU 2014-09 by the FASB), is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. These may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The new guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU 2014-09 by one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. This ASU is effective for public reporting companies for interim and annual periods beginning after December 15, 2017. The Company is currently evaluating its adoption method and the impact of the standard on its consolidated financial statements and has not yet determined the method by which the Company will adopt the standard in 2017.

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In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing” (Topic 606). In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross verses Net)” (Topic 606). These amendments provide additional clarification and implementation guidance on the previously issued ASU 2014-09, “Revenue from Contracts with Customers”. The amendments in ASU 2016-10 provide clarifying guidance on materiality of performance obligations; evaluating distinct performance obligations; treatment of shipping and handling costs; and determining whether an entity's promise to grant a license provides a customer with either a right to use an entity's intellectual property or a right to access an entity's intellectual property. The amendments in ASU 2016-08 clarify how an entity should identify the specified good or service for the principal versus agent evaluation and how it should apply the control principle to certain types of arrangements. The adoption of ASU 2016-10 and ASU 2016-08 is to coincide with an entity's adoption of ASU 2014-09, which we intend to adopt for interim and annual reporting periods beginning after December 15, 2017. The Company is currently evaluating the impact of the new standard.

In April 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation” (Topic 718). The FASB issued this update to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The updated guidance is effective for annual periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption of the update is permitted. The Company is currently evaluating the impact of the new standard.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 will make eight targeted changes to how cash receipts and cash payments are presented and classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017. The new standard will require adoption on a retrospective basis unless it is impracticable to apply, in which case it would be required to apply the amendments prospectively as of the earliest date practicable. The Company is currently in the process of evaluating the impact of ASU 2016-15 on its consolidated financial statements. 

The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations, or cash flows. 

Results of Operations

Results of Operations for the Three Months Ended July 31, 2017 Compared to Three Months Ended July 31, 2016

Oil Sales

During the three months ended July 31, 2017, the Company recognized $8,803 in oil and gas sales, compared to $0 for the three months ended July 31, 2016. The overall increase in sales of $8,803 is primarily due to the Company commencing production in Osage County, Oklahoma. The Company anticipates increasing revenue in subsequent quarters based on additional discoveries in Kern County, as well as from the Company’s prospects in Osage County, Oklahoma following the successful drilling of the Company’s W. Blackland #1-3 Well and S. Blackland #2-11 Well. Given current oil and gas prices; however, and the Company’s limited development budget, management does not anticipate deriving substantial revenue from existing oil and gas assets in the short-term; provided, however, in the event oil and gas prices rise from current levels, or in the event current drilling activity and re-completions results in additional proven reserves that can be extracted profitably at current oil and gas prices, management anticipates the addition of material oil and gas sales, although no assurances can be given.

Lease Operating Expense

During the three months ended July 31, 2017, lease operating expense was $18,362, as compared to $23,759 for the three months ended July 31, 2016. The overall decrease in lease operating expense of $5,397 was primarily attributable to management’s commitment to substantially reduce operating expenses in light of the current challenging oil price environment.

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Impairment of Oil and Gas Assets

The Company assesses all items classified as unproved property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: land relinquishment; intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. Significant changes in these factors could reduce our estimates of future net proceeds and accordingly could result in an impairment of our oil and gas assets. During the three months ended July 31, 2017, the Company reviewed the oil and gas assets for impairment and did not recognized an impairment charge.

General and Administrative Expense

General and administrative expense for the three months ended July 31, 2017 was $992,557, as compared to $1,708,141 for the three months ended July 31, 2016. The decrease was primarily attributable to decreases in salaries, professional fees and benefits and office and administrative expenses. These changes are outlined below:

	For the Three Months Ended	For the Three Months Ended
	July 31, 2017	July 31, 2016
Salaries and benefits	$578,423	$1,215,197
Professional fees	266,968	292,038
Office and administrative	147,166	200,906
Total	$992,557	$1,708,141

Salaries and benefits include non-cash stock-based compensation of $529,332 for three months ended July 31, 2017 compared to $1,150,197 for the three months ended July 31, 2016. The decrease in stock-based compensation of $858,467 from the three months ended July 31, 2017 was due to fewer awards made during the current period. General and administrative expenses decreased due to management’s commitment to substantially reduce expenses in light of the current challenging oil price environment.

Interest Income (Expense)

During the three months ended July 31, 2017, the Company recognized $132,745 in interest income (expense) compared to interest income of $141,259 for the three months ended July 31, 2016. During the three months ended July 31, 2017, the Company recorded interest income $194,599 accrued on the related party notes receivable. The interest income was offset by $37,378 and $24,476 which were the accretion of the debt discount and interest expense related to the $2.0 million secured financing.

Net Gain on Interests in Real Estate Rights

During the three months ended July 31, 2017, the Company recognized $271,490 net gain on its interest in real estate rights compared to $300,639 net gain for the three months ended July 31, 2016. The net gain on interest in real estate rights for the three months ended July 31, 2017 and 2016 was due to the sale of one condominium unit in each period by Fortis, and the resulting profits which were assigned to MegaWest pursuant to the Contribution Agreement, less the book value recorded by MegaWest. 

Liquidity and Capital Resources

At July 31, 2017, the Company had working capital of approximately $26.2 million, of which approximately $26.3 million, $1.1 million and $0.9 million of several notes receivable from a related party, an account receivable from a related party, and prepaid oil and gas assets, respectively.

Proceeds from the notes receivable from Fortis will not be available until such time as the Company has completed the redetermination of the fair market value of the Bandolier Interest, which has not occurred as of September 14, 2017, but is anticipated prior to December 31, 2017, In the event there is a shortfall from the valuation ascribed to the Bandolier Interest at the time of the Redetermination, as compared to the value ascribed to the Bandolier Interest in the Contribution Agreement, the Company will be required to provide Fortis with a cash payment in an amount equal to the shortfall, and any unfunded shortfall will likely result in the foreclosure on all or a portion of the Company’s entire equity interest in MegaWest, which equity interest has been pledged to Fortis.  No assurances can be given that the value of the Bandolier Interest will equal the valuation set forth in the Contribution Agreement, or if the value identified after the Redetermination is below the initial valuation, that we will be able to fund such shortfall. Any requirement to fund a shortfall will have a material and adverse effect on our operations and financial condition.

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In the event of a foreclosure of our equity interest in MegaWest resulting in such equity interest decreasing to less than a controlling interest in MegaWest, the assets conveyed to MegaWest under the terms of the Contribution Agreement may no longer be consolidated with the Company’s assets on the Company’s financial statements, and the Bandolier Interest may revert back to the Company.  As a result, our financial condition and results from operations may be adversely affected, and such affect will be material.

As a result of the utilization of cash in its operating activities, and the development of its assets, the Company has incurred losses since it commenced operations. In addition, the Company has a limited operating history.  At July 31, 2017, the Company had cash and cash equivalents of approximately $1.2 million. The Company’s primary source of operating funds since inception has been equity and note financings, as well as through the consummation of the Horizon Acquisition. While management believes that the current level of working capital is sufficient to maintain current operations as well as the planned added operations for the next 12 months, management intends to raise additional capital through debt and equity instruments in order to execute its business, operating and development plans. Management can provide no assurances that the Company will be successful in its capital raising efforts. In order to conserve capital, from time to time, management may defer certain development activity.

Operating Activities

During the three months ended July 31, 2017, operating activities used cash of $65,678 compared to $687,473 used in operating activities during the three months ended July 31, 2016. The Company incurred a net loss during the three months ended July 31, 2017 of $805,205 as compared to a net loss of $1,265,735 for the three months ended July 31, 2016. For three months ended July 31, 2017, the net loss was offset by non-cash items such as stock-based compensation, depreciation, depletion and accretion of asset retirement obligation, impairment of oil and gas assets, and the deferred tax liability. Cash provided by operations was also influenced by changes in accounts receivable, accrued interest on notes receivable, prepaid expenses and accounts payable and accrued expenses. For the three months ended July 31, 2016, the loss was offset by non-cash items such as stock-based compensation, depreciation, depletion and amortization, impairment of oil and gas assets, gain on sale of oil and gas assets and accretion of asset retirement obligation. Cash used in operations was also influenced by changes in accounts receivable, prepaid expenses and accounts payable and accrued expenses.

Investing Activities

Investing activities during the three months ended July 31, 2017 resulted in cash used of $1,398,430, as compared to cash provided of $2,735,283 during the three months ended July 31, 2016. During the three months ended July 31, 2017, the Company invested an additional $379,418 in Horizon Energy Partners compared to $525,000 in the comparable period in 2016. During the three months ended July 31, 2017, the Company received proceeds of $1,557,852 from profits in its real estate rights compared to $2,915,332 for the three months ended July 31, 2016. During the three months ended July 31, 2017, the Company incurred $736,964 of expenditures on oil and gas assets compared to $6,790 for the three months ended July 31, 2016. During the three months ended July 31, 2017, the Company executed notes receivable agreements with related parties resulting in the outlay of $1,558,501 compared to $2,947,129 during the period ended July 31, 2016. During the three months ended July 31, 2016, the Company received $3,364,817 from the acquisition of Horizon Investments.

Financing Activities

Financing activities during the three months ended July 31, 2017 resulted in cash provided of $2,000,000, as compared to $0 during the three months ended July 31, 2016. The increase was due to the issuance of a $2.0 million note payable during the current period.

Capitalization

The number of outstanding shares and the number of shares that could be issued if all common stock equivalents are converted to shares is as follows: 

As of	July 31,  2017	July 31,  2016
Common shares	15,840,143	4,263,711
Stock options	2,574,682	2,502,182
Stock purchase warrants	973,669	133,333
	19,388,494	6,899,226

Off-Balance Sheet Arrangements

None.

- 25 -

ITEM 3. QUANTITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable

ITEM 4. CONTROLS AND PROCEDURES

A. Material Weaknesses

As discussed in Item 9A of our Annual Report on Form 10-K for the fiscal year ended April 30, 2017, we identified material weaknesses in the design and operation of our internal controls. The material weaknesses are due to the limited number of employees, which impacts our ability to conduct a thorough internal review, and the Company’s reliance on external accounting personnel to prepare financial statements.

To remediate the material weakness, the Company is developing a plan to design and implement the operation of our internal controls.  Upon the Company obtaining additional capital, the Company intends to hire additional accounting staff, and operations and administrative executives in the future to address its material weaknesses.

We will continue to monitor and assess our remediation initiatives to ensure that the aforementioned material weaknesses are remediated.

B. Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in the Company’s filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. The Company’s management, with the participation of its principal executive and principal financial officers, has evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon that evaluation and solely due to the unremediated material weaknesses described above, the Company’s principal executive and financial officers have concluded that such disclosure controls and procedures were not effective for the purpose for which they were designed as of the end of such period. As a result of this conclusion, the financial statements for the period covered by this report were prepared with particular attention to the unremediated material weaknesses previously disclosed. Accordingly, management believes that the consolidated financial statements included in this report fairly present, in all material respects, the Company’s financial condition, results of operations and cash flows as of and for the periods presented, in accordance with US GAAP, notwithstanding the unremediated weaknesses.

C. Changes in Internal Control over Financial Reporting

There was no change in the Company’s internal control over financial reporting that was identified in connection with such evaluation that occurred during the period covered by this Quarterly Report on Form 10-Q that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

(a) In January 2010, the Company experienced a flood in its Calgary office premises as a result of a broken water pipe. There was significant damage to the premises rendering them unusable until the landlord had completed remediation. Pursuant to the lease contract, the Company asserted that rent should be abated during the remediation process and accordingly, the Company did not pay any rent after December 2009. During the remediation process, the Company engaged an independent environmental testing company to test for air quality and for the existence of other potentially hazardous conditions. The testing revealed the existence of potentially hazardous mold and the consultant provided specific written instructions for the effective remediation of the premises. During the remediation process, the landlord did not follow the consultant’s instructions and correct the potentially hazardous mold situation and subsequently in June 2010 gave notice and declared the premises to be ready for occupancy. The Company re-engaged the consultant to re-test the premises and the testing results again revealed the presence of potentially hazardous mold. The Company determined that the premises were not fit for re-occupancy and considered the landlord to be in default of the lease. The Landlord subsequently terminated the lease.

On January 30, 2014, the landlord filed a Statement of Claim against the Company for rental arrears in the amount aggregating CAD $759,000 (approximately USD $625,000 as of September 13, 2017). The Company filed a defense and on October 20, 2014, it filed a summary judgment application stating that the landlord’s claim is barred as it was commenced outside the 2-year statute of limitation period under the Alberta Limitations Act. The landlord subsequently filed a cross-application to amend its Statement of Claim to add a claim for loss of prospective rent in an amount of CAD $665,000 (approximately USD $548,000 as of September 13, 2017). The applications were heard on June 25, 2015 and the court allowed both the Company’s summary judgment application and the landlord’s amendment application.  Both of these orders were appealed though two levels of the Alberta courts and the appeals were dismissed at both levels. The net effect is that the landlord's claim for loss of prospective rent is to proceed.

- 26 -

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Commission”) that the Company was not in compliance with regulations promulgated by the Commission. The Company was therefore deemed to have lost its corporate privileges within the State of Texas and as a result, all wells within the state would have to be plugged. The Commission therefore collected $25,000 from the Company, which was originally deposited with the Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Commission also reserved its right to separately seek any remedies against the Company resulting from its noncompliance.

(c) On August 11, 2014, Martha Donelson and John Friend amended their complaint in an existing lawsuit by filing a class action complaint styled: Martha Donelson and John Friend, et al. v. United States of America, Department of the Interior, Bureau of Indian Affairs and Devon Energy Production, LP, et al., Case No. 14-CV-316-JHP-TLW, United States District Court for the Northern District of Oklahoma (the “Proceeding”).  The plaintiffs added as defendants twenty-seven (27) specifically named operators, including Spyglass, as well as all Osage County lessees and operators who have obtained a concession agreement, lease or drilling permit approved by the Bureau of Indian Affairs (“BIA”) in Osage County allegedly in violation of National Environmental Policy Act (“NEPA”).  Plaintiffs seek a declaratory judgment that the BIA improperly approved oil and gas leases, concession agreements and drilling permits prior to August 12, 2014, without satisfying the BIA’s obligations under federal regulations or NEPA, and seek a determination that such oil and gas leases, concession agreements and drilling permits are void ab initio.  Plaintiffs are seeking damages against the defendants for alleged nuisance, trespass, negligence and unjust enrichment.  The potential consequences of such complaint could jeopardize the corresponding leases.

On October 7, 2014, Spyglass, along with other defendants, filed a Motion to Dismiss the August 11, 2014 Amended Complaint on various procedural and legal grounds. Following the significant briefing, the Court, on March 31, 2016, granted the Motion to Dismiss as to all defendants and entered a judgment in favor of the defendants against the plaintiffs. On April 14, 2016, Spyglass with the other defendants, filed a Motion seeking its attorneys’ fees and costs. The motion remains pending. On April 28, 2016, the plaintiffs filed three motions: a Motion to Amend or Alter the Judgment; a Motion to Amend the Complaint; and a Motion to Vacate Order. On November 23, 2016, the Court denied all three of Plaintiffs’ motions.  On December 6, 2016, Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals.  That appeal is pending as of the effective date of this response. There is no specific timeline by which the Court of Appeals must render a ruling. Spyglass intends to continue to vigorously defend its interest in this matter. 

(d) MegaWest Energy Missouri Corp. (“MegaWest Missouri”), a wholly owned subsidiary of the Company, is involved in two cases related to oil leases in West Central, Missouri.  The first case (James Long and Jodeane Long v. MegaWest Energy Missouri and Petro River Oil Corp., case number 13B4-CV00019) is a case for unlawful detainer, pursuant to which the plaintiffs contend that MegaWest Missouri oil and gas lease has expired and MegaWest Missouri is unlawfully possessing the plaintiffs’ real property by asserting that the leases remain in effect.  The case was originally filed in Vernon County, Missouri on September 20, 2013.  MegaWest Missouri filed an Answer and Counterclaims on November 26, 2013 and the plaintiffs filed a motion to dismiss the counterclaims. MegaWest Missouri filed a motion for Change of Judge and Change of Venue and the case was transferred to Barton County.  The court granted the motion to dismiss the counterclaims on February 3, 2014.  As to the other allegations in the complaint, the matter is still pending.

MegaWest Missouri filed a second case on October 14, 2014 (MegaWest Energy Missouri Corp. v. James Long, Jodeane Long, and Arrow Mines LLC, case number 14VE-CV00599).  This case is pending in Vernon County, Missouri.  Although the two cases are separate, they are interrelated.  In the Vernon County case, MegaWest Missouri has made claims for: (1) replevin for personal property; (2) conversion of personal property; (3) breach of the covenant of quiet enjoyment regarding the lease; (4) constructive eviction of the lease; (5) breach of fiduciary obligation against James Long; (6) declaratory judgment that the oil and gas lease did not terminate; and (7) injunctive relief to enjoin the action pending in Barton County, Missouri.  The plaintiffs filed a motion to dismiss on November 4, 2014, and Arrow Mines, LLC filed a motion to dismiss on November 13, 2014.  Both motions remain pending, and MegaWest Missouri will file an opposition to the motions in the near future. 

(e) The Company is from time to time involved in legal proceedings in the ordinary course of business. It does not believe that any of these claims and proceedings against it is likely to have, individually or in the aggregate, a material adverse effect on its financial condition or results of operations.

ITEM 1A. RISK FACTORS

Our results of operations and financial condition are subject to numerous risks and uncertainties described in our Annual Report on Form 10-K for our fiscal year ended April 30, 2017, filed on July 31, 2017. You should carefully consider these risk factors in conjunction with the other information contained in this Quarterly Report. Should any of these risks materialize, our business, financial condition and future prospects could be negatively impacted. As of July 31, 2017, there have been no material changes to the disclosures made in the above-referenced Form 10-K.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5. OTHER INFORMATION.

(a) There is no information required to be disclosed on Form 8-K during the period covered by this Form 10-Q that was not so reported.

(b) There were no material changes to the procedures by which security holders may recommend nominees to the registrant’s Board of Directors during the quarter ended July 31, 2017.

ITEM 6. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements.

Our financial statements as set forth in the Index to Financial Statements attached hereto commencing on page F-1 are hereby incorporated by reference.

(b) Exhibits.

The following exhibits, which are numbered in accordance with Item 601 of Regulation S-K, are filed herewith or, as noted, incorporated by reference herein:

Exhibit Number	Exhibit Description
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

- 28 -

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PETRO RIVER OIL CORP.
	By:	/s/ Scot Cohen
	Name:	Scot Cohen
	Title:	Executive Chairman
	By:	/s/ David Briones
	Name:	David Briones
	Title	Chief Financial Officer
Date: September 14, 2017

- 29 -

EX-31.1

Exhibit 31.1

CERTIFICATION BY PRINCIPAL EXECUTIVE OFFICER

I, Scot Cohen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Petro River Oil Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this quarterly report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: September 14, 2017

By:	/s/ Scot Cohen
	Scot Cohen
	Executive Chairman

EX-31.2

Exhibit 31.2

CERTIFICATION BY PRINCIPAL FINANCIAL OFFICER

I, David Briones, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Petro River Oil Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this quarterly report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 

Date: September 14, 2017

By:	/s/ David Briones
	David Briones
	Chief Financial Officer (Principal Financial Officer)

 

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Petro River Oil Corp. (the “Company”) on Form 10-Q for the period ended July 31, 2017, as filed with the Securities Exchange Commission on the date hereof (the “Report”), I, Scot Cohen, Executive Chairman of the Company, certify, pursuant to 18 U. S. C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 14, 2017

/s/ Scot Cohen

Scot Cohen

Executive Chairman

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

In connection with the Quarterly Report of Petro River Oil Corp (the “Company”) on Form 10-Q for the period ended July 31, 2017, as filed with the Securities Exchange Commission on the date hereof (the “Report”), I, David Briones, Chief Financial Officer of the Company, certify, pursuant to 18 U. S. C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 14, 2017

/s/ David Briones

David Briones

Chief Financial Officer (Principal Financial Officer)

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	3 Months Ended
	Jul. 31, 2017	Sep. 14, 2017
Document And Entity Information
Entity Registrant Name	Petro River Oil Corp.
Entity Central Index Key	0001172298
Document Type	10-Q
Document Period End Date	Jul. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--04-30
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		15,843,142
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2018

XML

Consolidated Balance Sheets (Unaudited) - USD ($)	Jul. 31, 2017	Apr. 30, 2017
Current Assets:
Cash and cash equivalents	$ 1,167,124	$ 631,232
Accounts receivable - oil and gas	8,669	8,423
Accounts receivable - real estate - related party	1,146,673	2,123,175
Accrued interest on notes receivable - related party	992,309	797,710
Interest in real estate rights	0	309,860
Prepaid expenses and other current assets	32,367	207,831
Prepaid oil and gas development costs	894,879	613,480
Notes receivable - related party, current portion	26,344,883	24,786,382
Total Current Assets	30,586,904	29,478,093
Oil and gas assets, full cost method
Costs subject to amortization, net	1,973,313	1,234,806
Costs not being amortized, net	858,828	858,830
Property, plant and equipment, net of accumulated depreciation of $184,330 and $184,140, respectively	1,392	1,582
Investment in Horizon Energy Partners	1,592,418	1,213,000
Other assets	17,133	17,133
Total Long-term Assets	4,443,084	3,325,351
Total Assets	35,029,988	32,803,444
Current Liabilities:
Accounts payable and accrued expenses	376,597	120,233
Deferred tax liability	3,640,928	3,442,724
Asset retirement obligations, current portion	406,403	406,403
Total Current Liabilities	4,423,928	3,969,360
Long-term liabilities:
Asset retirement obligations, net of current portion	162,764	152,293
Note payable, net of debt discount of $914,678 and $0, respectively	1,085,322	0
Total Long-term Liabilities	1,248,086	152,293
Total Liabilities	5,672,014	4,121,653
Commitments and contingencies
Equity:
Preferred shares	0	0
Common shares - 100,000,000 authorized; par value $0.00001; 15,840,143 and 15,827,921 issued and outstanding, respectively	158	158
Additional paid-in capital	48,162,461	46,681,073
Accumulated deficit	(31,489,686)	(30,609,910)
Total Petro River Oil Corp. Equity	16,672,933	16,071,321
Non-controlling interest	12,685,041	12,610,470
Total Equity	29,357,974	28,681,791
Total Liabilities and Equity	35,029,988	32,803,444
Preferred B Shares [Member]
Equity:
Preferred shares	$ 0	$ 0

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Jul. 31, 2017	Apr. 30, 2017
Accumulated depreciation of property, plant and equipment	$ 184,330	$ 184,140
Note payable debt discount	$ 914,678	$ 0
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, par value	$ .00001	$ 0.00001
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, shares authorized	100,000,000	100,000,000
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares issued	15,840,143	15,827,921
Common stock, shares outstanding	15,840,143	15,827,921
Preferred B Shares [Member]
Preferred stock, shares authorized	295,00.	29,500
Preferred stock, par value	$ 0.00001	$ 0.00001
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0

XML

Consolidated Statements of Operations - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016
Revenues
Oil and natural gas sales	$ 8,803	$ 0
Total Revenues	8,803	0
Operating Expenses
Lease operating expenses	18,362	23,759
Depreciation, depletion and accretion	9,120	4,396
Gain on sale of oil and gas assets	0	(216,580)
General and administrative	992,557	1,708,141
Total Operating Expenses	1,020,039	1,519,716
Operating Loss	(1,011,236)	(1,519,716)
Other Income (Expense)
Interest income (expense) - net	132,745	141,259
Net gain on real estate rights	271,490	300,639
Other income	404,235	441,898
Net Loss Before Income Tax Provision	(607,001)	(1,077,818)
Income Tax Provision	198,204	187,917
Net Loss	(805,205)	(1,265,735)
Net (Loss) Income Attributable to Non-controlling Interest	74,571	47,675
Net Loss Attributable to Petro River Oil Corp. Shareholders	$ (879,776)	$ (1,313,410)
Basic and Diluted Net Loss Per Common Share	$ (.06)	$ (0.09)
Weighted average number of common shares outstanding - Basic and diluted	15,835,095	15,450,826

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (805,205)	$ (1,265,735)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Stock-based compensation	529,332	1,150,197
Depreciation, depletion and accretion	9,120	4,396
Amortization of debt discount	37,378	0
Gain on sale of oil and gas assets	0	(216,580)
Net gain on interest in real estate rights	(271,490)	(300,639)
Deferred income tax expense	198,204	187,917
Changes in operating assets and liabilities:
Accounts receivable - oil and gas	(246)	903
Accrued interest on notes receivable- related party	(194,599)	(141,259)
Prepaid expenses and other current assets	175,464	(66,867)
Accounts payable and accrued expenses	256,364	(39,806)
Net Cash Used in Operating Activities	(65,678)	(687,473)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of interest in real estate rights	1,557,852	2,915,332
Prepaid oil and gas assets	(281,399)	(65,947)
Issuance of notes receivable - related party	(1,558,501)	(2,947,129)
Capitalized expenditures on oil and gas assets	(736,964)	(6,790)
Cash received from acquistion of Horizon Investments	0	3,364,817
Cash paid for cost method investment	(379,418)	(525,000)
Net Cash (Used in) Provided by Investing Activities	(1,398,430)	2,735,283
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable - related party	2,000,000	0
Net Cash Provided by Financing Activities	2,000,000	0
Change in cash and cash equivalents	535,892	2,047,810
Cash and cash equivalents, beginning of period	631,232	774,751
Cash and cash equivalents, end of period	1,167,124	2,822,561
Cash paid during the period for:
Income taxes	34,052	3,789
Interest paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Reclassification from prepaid oil and gas development costs to oil and gas assets not being amortized	0	761,444
Asset retirement obligation from drilling activities	7,500	0
Warrants issued with notes payable	$ 952,056	$ 0

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Organization

3 Months Ended

Jul. 31, 2017

Organization And Liquidity

Organization

Petro River Oil Corp. (the “Company”) is an independent energy company focused on the exploration and development of conventional oil and gas assets with low discovery and development costs. The Company is currently focused on moving forward with drilling wells on several of its properties owned directly and indirectly through its interest in Horizon Energy Partners, LLC (“Horizon Energy”), as well as taking advantage of the relative depressed market in oil prices to enter highly prospective plays with Horizon Energy and other industry-leading partners. Diversification over a number of projects, each with low initial capital expenditures and strong risk reward characteristics, reduces risk and provides cross-functional exposure to a number of attractive risk adjusted opportunities.

The Company’s core holdings are in Osage County, Oklahoma and in Kern County, California.   Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company now has exposure to a portfolio of several domestic and international oil and gas assets consisting of highly prospective conventional plays diversified across project type, geographic location and risk profile, as well as access to a broad network of industry leaders from Horizon Investment’s 20% interest in Horizon Energy.  Horizon Energy is an oil and gas exploration and development company owned and managed by former senior oil and gas executives.  It has a portfolio of domestic and international assets, including two assets located in the United Kingdom, adjacent to the giant Wytch Farm oil field, the largest onshore oil field in Western Europe.  Other projects include the proposed redevelopment of a large oil field in Kern County, California and the development of an additional recent discovery in Kern County.  Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

In light of the challenging oil price environment and capital markets, management is focusing on specific target acquisitions and investments, limiting operating expenses and exploring farm-in and joint venture opportunities for the Company’s oil and gas assets. No assurances can be given that management will be successful.  

Recent Developments

Kern County Drilling Program: On July 18, 2017, the Company announced a new oil field discovery upon successful drilling of the Cattani-Rennie 47X-15 exploration well (“CR 47X”) in its Sunset Boulevard prospect in Kern County, California. The Company is currently conducting well tests on multiple zones. Results are expected in October 2017. The Company owns a 19.25% interest in the Sunset Boulevard prospect in Kern County field based on a 13.75% direct working interest, and a 5.5% indirect working interest through its 20% equity investment in Horizon Energy.

On August 15, 2017, the Company announced a second oil field discovery upon successful drilling of the Chardonnay 47X-35 exploration well (the “Chardonnay 47X”) at its Grapevine project in Kern County, California. The Company is currently conducting well tests, and expects to announce production results in October 2017. The Company owns an 8% indirect interest in the Grapevine project through its 20% equity investment in Horizon Energy.

Osage County Drilling Program:  On May 8, 2017, the Company announced the discovery of a new oil field on the Company's 106,500-acre concession in Osage County, Oklahoma (the “Osage Concession”).  The Company’s Chat #2-11, now known as the S. Blackland #2-11, successfully tested a seismically-delineated structure on the Company’s concession. The 30-day oil flow test indicates initial production rates of up to 35 BOE per day. 

On May 30, 2017, the Company announced a second oil discovery on its Osage Concession.  The 30-day oil flow test of the Red Fork 1-3 well, now known as the W. Blackland #1-3, indicates initial production rates of up to 71 BOE per day.

The Company recently identified 1,730 acres of structural closures highlighted in its existing 3D seismic, and confirmed as a result of the successful drilling of W. Blackland #1-3 and S. Blackland #2-11.  The Company does not expect to have any meaningful production until early 2018 following completion of its 2017 drilling program.  Currently, both the W. Blackland #1-3 and S. Blackland #2-11 wells are shut-in until late 2017 in order to build production facilities.

$2.0 Million Secured Note Financing. On June 13, 2017, the Company entered into a Securities Purchase Agreement (“Purchase Agreement”) with Petro Exploration Funding, LLC (“Funding Corp.”), pursuant to which the Company issued to Funding Corp. a senior secured promissory note to finance the Company’s working capital requirements, in the principal amount of $2.0 million (“Secured Note”). As additional consideration for the note financing, the Company issued to Funding Corp. (i) a warrant to purchase 840,336 shares of the Company’s common stock, $0.00001 par value, and (ii) an overriding royalty interest equal to 2% in all production from the Company’s interest in the Company’s concessions located in Osage County, Oklahoma, currently held by Spyglass pursuant to an Assignment of Overriding Royalty Interests (the “2017 Override”).

The Secured Note accrues interest at a rate of 10% per annum, and matures on June 30, 2020. To secure the repayment of all amounts due under the terms of the Secured Note, the Company entered into a Security Agreement, pursuant to which the Company granted to Funding Corp. a security interest in all assets of the Company. The first interest payment will be due on June 1, 2018, and each six-month anniversary thereafter until the outstanding principal balance of the Secured Note is paid in full.

The warrant is exercisable immediately upon issuance, for an exercise price per share equal to $2.38 per share, and shall terminate, if not previously exercised, five years from the date of issuance. Scot Cohen, a member of the Company’s Board of Directors and a substantial stockholder of the Company, owns or controls 31.25% of Funding Corp.

Purchase of 2% Overriding Royalty Interest. On August 14, 2017, following a review of the Company’s capital requirements necessary to fund its 2017 development program, the Company’s independent directors consented to Scot Cohen’s purchase from various third parties who collectively held a 2% overriding royalty interest that originally burdened the Osage County, Oklahoma concession for $250,000 (the “Original Override”). Mr. Cohen agreed to sell the Original Override to the Company at the same price paid by him (plus market interest on his capital) upon a determination by the Company to finance the Osage County development plan on terms similar to the June 13, 2017 secured note financing.

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Basis of Preparation

3 Months Ended

Jul. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Preparation

The accompanying unaudited interim consolidated financial statements are prepared in accordance with U.S. GAAP and include the accounts of the Company and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation. Non–controlling interest represents the minority equity investment in the Company’s subsidiaries, plus the minority investors’ share of the net operating results and other components of equity relating to the non–controlling interest.

These unaudited consolidated financial statements include the Company and the following subsidiaries:

Petro Spring, LLC, PO1, LLC, Petro River UK Limited, Horizon I Investments, LLC and MegaWest Energy USA Corp. and MegaWest Energy USA Corp.’s wholly owned subsidiaries:

MegaWest Energy Texas Corp.

MegaWest Energy Kentucky Corp.

MegaWest Energy Missouri Corp.

Also contained in the unaudited consolidated financial statements is the financial information of the Company’s 58.51% owned subsidiary, MegaWest Energy Kansas Corporation (“MegaWest”), which resulted from a transaction with Fortis Property Group, LLC, a Delaware limited liability company (“Fortis”) consummated on October 15, 2015 (the “MegaWest Transaction”). The MegaWest Transaction includes the Company’s contribution of its 50% interest in Bandolier Energy LLC. 

The unaudited consolidated financial information furnished herein reflects all adjustments, consisting solely of normal recurring items, which in the opinion of management are necessary to fairly state the financial position of the Company and the results of its operations for the periods presented. This report should be read in conjunction with the Company’s consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended April 30, 2017 filed with the Securities and Exchange Commission (the “SEC”) on July 31, 2017. The Company assumes that the users of the interim financial information herein have read or have access to the audited financial statements for the preceding fiscal year and that the adequacy of additional disclosure needed for a fair presentation may be determined in that context. Accordingly, footnote disclosure, which would substantially duplicate the disclosure contained in the Company’s Form 10-K for the year ended April 30, 2017 has been omitted. The results of operations for the interim periods presented are not necessarily indicative of results for the entire year ending April 30, 2018.

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Significant Accounting Policies

3 Months Ended

Jul. 31, 2017

Accounting Policies [Abstract]

Significant Accounting Policies

 (a) Use of Estimates:

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

The Company’s financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties, and timing and costs associated with its asset retirement obligations, as well as those related to the fair value of stock options, stock warrants and stock issued for services. While we believe that our estimates and assumptions used in preparation of the financial statements are appropriate, actual results could differ from those estimates.

 (b) Cash and Cash Equivalents:

Cash and cash equivalents include all highly liquid monetary instruments with original maturities of three months or less when purchased. These investments are carried at cost, which approximates fair value. Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash deposits. The Company maintains its cash in institutions insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, the Company’s cash and cash equivalent balances may be uninsured or in amounts that exceed the FDIC insurance limits. At July 31, 2017, approximately $788,831 of the Company’s cash balances were uninsured. The Company has not experienced any loses on such accounts.

 (c) Receivables:

Receivables that management has the intent and ability to hold for the foreseeable future are reported in the balance sheet at outstanding principal adjusted for any charge-offs and the allowance for doubtful accounts. Losses from uncollectible receivables are accrued when both of the following conditions are met: (a) Information available before the financial statements are issued or are available to be issued indicates that it is probable that an asset has been impaired at the date of the financial statements, and (b) The amount of the loss can be reasonably estimated. These conditions may be considered in relation to individual receivables or in relation to groups of similar types of receivables. If the conditions are met, an accrual shall be made even though the particular receivables that are uncollectible may not be identifiable. The Company reviews individually each receivable for collectability and performs on-going credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current credit worthiness, as determined by the review of their current credit information; and determines the allowance for doubtful accounts based on historical write-off experience, customer specific facts and general economic conditions that may affect a client’s ability to pay. Bad debt expense is included in general and administrative expenses, if any.

Credit losses for receivables (uncollectible receivables), which may be for all or part of a particular receivable, shall be deducted from the allowance. The related receivable balance shall be charged off in the period in which the receivables are deemed uncollectible. Recoveries of receivables previously charged off shall be recorded when received. The Company charges off its account receivables against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

The allowance for doubtful accounts at July 31, 2017 and April 30, 2017 was $0.

 (d) Interest in Real Estate Rights:

Interest in real estate rights contributed by Fortis related to real properties that Fortis plans to sell within one year. Since these properties are contributed by Fortis, a related party, the rights are stated on balance sheet at the cost basis of Fortis.

 (e) Oil and Gas Operations:

Oil and Gas Properties: The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the costs of both successful and unsuccessful exploration and development activities are capitalized as oil and gas property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country, in which case a gain or loss would be recognized in the consolidated statements of operations. All of the Company’s oil and gas properties are located within the continental United States, its sole cost center.

Oil and gas properties may include costs that are excluded from costs being depleted. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and in process exploration drilling costs. All costs excluded are reviewed at least annually to determine if impairment has occurred.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate. For the three months ended July 31, 2017, the Company evaluated and recorded no impairment on these properties.

Proved Oil and Gas Reserves: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. All of the Company’s oil and gas properties with proven reserves were impaired to the salvage value prior to the Bandolier transaction. The price used to establish economic producibility is the average price during the 12-month period preceding the end of the entity’s fiscal year and calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within such 12-month period. For the three months ended July 31, 2017, the Company did not record an impairment charge on its proved oil and gas properties.

Depletion, Depreciation and Amortization: Depletion, depreciation and amortization is provided using the unit-of-production method based upon estimates of proved oil and gas reserves with oil and gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is deducted from the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. 

In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by the Company’s geologists and engineers which require significant judgment, as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expenses. There have been no material changes in the methodology used by the Company in calculating depletion, depreciation and amortization of oil and gas properties under the full cost method during the three months ended July 31, 2017 and 2016.  

 (f) Investments – Cost Method and Equity Method:

Investments held in stock of entities other than subsidiaries, namely corporate joint ventures and other non-controlled entities usually are accounted for by one of three methods: (i) the fair value method, (ii) the equity method, or (iii) the cost method. The equity method tends to be most appropriate if an investment enables the investor to influence the operating or financial policies of the investee. The cost basis is utilized for investments that are less than 20% owned, and the Company does not exercise significant influence over the operating and financial policies of the investee. Under the cost method, investments are held at historical cost.

 (g) Fair Value of Financial Instruments:

The Company follows paragraph 825-10-50-10 of the FASB Accounting Standards Codification for disclosures about fair value of its financial instruments and paragraph 820-10-35-37 of the FASB Accounting Standards Codification (“Paragraph 820-10-35-37”) to measure the fair value of its financial instruments. Paragraph 820-10-35-37 establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, Paragraph 820-10-35-37 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by Paragraph 820-10-35-37 are described below:

Level 1	Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.
Level 2	Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3	Pricing inputs that are generally observable inputs and not corroborated by market data.

Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable.

The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

The carrying amount of the Company’s financial assets and liabilities, such as cash, prepaid expenses, and accounts payable and accrued liabilities approximate their fair value because of the short maturity of those instruments.

Transactions involving related parties cannot be presumed to be carried out on an arm’s-length basis, as the requisite conditions of competitive, free-market dealings may not exist. Representations about transactions with related parties, if made, shall not imply that the related party transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions unless such representations can be substantiated.

 (h) Stock-Based Compensation:

Generally, all forms of stock-based compensation, including stock option grants, warrants, and restricted stock grants are measured at their fair value utilizing an option pricing model on the award’s grant date, based on the estimated number of awards that are ultimately expected to vest.

Under fair value recognition provisions, the Company recognizes equity–based compensation net of an estimated forfeiture rate and recognizes compensation cost only for those shares expected to vest over the requisite service period of the award.

The fair value of option award is estimated on the date of grant using the Black–Scholes option valuation model. The Black–Scholes option valuation model requires the development of assumptions that are input into the model. These assumptions are the expected stock volatility, the risk–free interest rate, the option’s expected life, the dividend yield on the underlying stock and the expected forfeiture rate. Expected volatility is calculated based on the historical volatility of the Company’s common stock over the expected option life and other appropriate factors. Risk–free interest rates are calculated based on continuously compounded risk–free rates for the appropriate term. The dividend yield is assumed to be zero as the Company has never paid or declared any cash dividends on its common stock and does not intend to pay dividends on the common stock in the foreseeable future. The expected forfeiture rate is estimated based on historical experience.

Determining the appropriate fair value model and calculating the fair value of equity–based payment awards requires the input of the subjective assumptions described above. The assumptions used in calculating the fair value of equity–based payment awards represent management’s best estimates, which involve inherent uncertainties and the application of management’s judgment. As a result, if factors change and the Company uses different assumptions, the equity–based compensation expense could be materially different in the future. In addition, the Company is required to estimate the expected forfeiture rate and recognize expense only for those shares expected to vest. If the actual forfeiture rate is materially different from our estimate, the equity–based compensation expense could be significantly different from what the Company has recorded in the current period. 

The Company determines the fair value of the stock–based payments to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.  If the fair value of the equity instruments issued is used, it is measured using the stock price and other measurement assumptions as of the earlier of either (1) the date at which a commitment for performance by the counterparty to earn the equity instruments is reached, or (2) the date at which the counterparty’s performance is complete.

The expenses resulting from stock-based compensation are recorded as general and administrative expenses in the consolidated statement of operations, depending on the nature of the services provided.

 (i) Income Taxes:

Income Tax Provision

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance to the extent management concludes it is more likely than not that the assets will not be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the statements of operations in the period that includes the enactment date.

The Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent (50%) likelihood of being realized upon ultimate settlement.

The estimated future tax effects of temporary differences between the tax basis of assets and liabilities are reported in the accompanying consolidated balance sheets, as well as tax credit carry-backs and carry-forwards. The Company periodically reviews the recoverability of deferred tax assets recorded on its consolidated balance sheets and provides valuation allowances as management deems necessary.

Management makes judgments as to the interpretation of the tax laws that might be challenged upon an audit and cause changes to previous estimates of tax liability. In addition, the Company operates within multiple taxing jurisdictions and is subject to audit in these jurisdictions. In management’s opinion, adequate provisions for income taxes have been made for all years. If actual taxable income by tax jurisdiction varies from estimates, additional allowances or reversals of reserves may be necessary.

Uncertain Tax Positions

The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard, or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained.

At July 31, 2017 and April 30, 2017, the Company had approximately $3,640,928 and $3,442,724, respectively, of liabilities for uncertain tax positions. Interpretation of taxation rules relating to net operating loss utilization in real estate transactions give rise to uncertain positions. In connection with the uncertain tax position, there were no interest or penalties recorded as the position is expected but the tax returns are not yet due.

The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results.

The number of years with open tax audits varies depending on the tax jurisdiction. The Company’s major taxing jurisdictions include the United States (including applicable states).

 (j) Per Share Amounts:

Basic net income (loss) per common share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. For the three months ended July 31, 2017 and 2016, potentially dilutive securities were not included in the calculation of diluted net loss per share because to do so would be anti-dilutive.

The Company had the following common stock equivalents at July 31, 2017 and 2016:

	July 31, 2017		July 31, 2016
Stock Options		2,574,682		2,502,182
Stock Purchase Warrants		973,669		133,333
Total		3,548,351		2,635,515

 (k) Recent Accounting Pronouncements:

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard’s core principle (issued as ASU 2014-09 by the FASB), is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. These may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The new guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU 2014-09 by one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. This ASU is effective for public reporting companies for interim and annual periods beginning after December 15, 2017. The Company is currently evaluating its adoption method and the impact of the standard on its consolidated financial statements and has not yet determined the method by which the Company will adopt the standard in 2017.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing” (Topic 606). In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross verses Net)” (Topic 606). These amendments provide additional clarification and implementation guidance on the previously issued ASU 2014-09, “Revenue from Contracts with Customers”. The amendments in ASU 2016-10 provide clarifying guidance on materiality of performance obligations; evaluating distinct performance obligations; treatment of shipping and handling costs; and determining whether an entity's promise to grant a license provides a customer with either a right to use an entity's intellectual property or a right to access an entity's intellectual property. The amendments in ASU 2016-08 clarify how an entity should identify the specified good or service for the principal versus agent evaluation and how it should apply the control principle to certain types of arrangements. The adoption of ASU 2016-10 and ASU 2016-08 is to coincide with an entity's adoption of ASU 2014-09, which we intend to adopt for interim and annual reporting periods beginning after December 15, 2017. The Company is currently evaluating the impact of the new standard.

In April 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation” (Topic 718). The FASB issued this update to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The updated guidance is effective for annual periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption of the update is permitted. The Company is currently evaluating the impact of the new standard.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 will make eight targeted changes to how cash receipts and cash payments are presented and classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017. The new standard will require adoption on a retrospective basis unless it is impracticable to apply, in which case it would be required to apply the amendments prospectively as of the earliest date practicable. The Company is currently in the process of evaluating the impact of ASU 2016-15 on its consolidated financial statements. 

The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations, or cash flows. 

 (l) Subsequent Events:

The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration. 

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Accounts Receivable - Related Party

3 Months Ended

Jul. 31, 2017

Accounting Policies [Abstract]

Accounts Receivable - Related Party

On October 15, 2015, the Company entered into a contribution agreement (the “Contribution Agreement”) with MegaWest and Fortis pursuant to which the Company and Fortis each agreed to contribute certain assets to MegaWest in exchange for shares of MegaWest common stock (“MegaWest Shares”) (the “MegaWest Transaction”). 

Upon execution of the Contribution Agreement, Fortis transferred its interest in 30 condominium units and the right to any profits and proceeds therefrom. For each of the three months ended July 31, 2017 and 2016, Fortis sold 1 condominium unit, and MegaWest recorded a net gain on interest in real estate rights of $271,490 and $300,639, respectively. As of July 31, 2017, the Company had an accounts receivable – related party in the amount of $1,146,673 related to interest in real estate rights of condominium units sold.

The accounts receivable and the Company’s interest in real estate reflected on the Company’s balance sheet are assets held by MegaWest, and are controlled by MegaWest’s board of directors, consisting of two members appointed by Fortis, and one by the Company. The relative composition of the board of directors of MegaWest shall continue as long as Fortis has an equity interest in MegaWest.

Proceeds from the amounts receivable from Fortis will not be available until such time as the Company has completed its evaluation of the Bandolier prospects. In this regard, the Contribution Agreement provided for a redetermination of the fair market value of the Bandolier Interest at any time following the six month anniversary after the execution thereof (the “Redetermination”),  Upon a Redetermination, which has not occurred as of September 14, 2017, but is anticipated prior to December 31, 2017, in the event there is a shortfall from the valuation ascribed to the Bandolier Interest at the time of the Redetermination, as compared to the value ascribed to the Bandolier Interest in the Contribution Agreement, the Company will be required to provide Fortis with a cash payment in an amount equal to the shortfall.  If the Company is unable to deliver to Fortis the cash payment required after the Redetermination, if any, the board of directors of MegaWest shall have the right to exercise certain remedies against the Company, including a right to foreclose on the Company’s entire equity in MegaWest, which equity interest has been pledged to Fortis under the terms of the Contribution Agreement.  In the event of foreclosure, the Bandolier Interest would revert back to the Company, and the Company would record a loss for the amount of the notes receivable, interest in real estate rights, accounts receivable – related party, and any accrued interest.

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Notes Receivable - Related Party

3 Months Ended

Jul. 31, 2017

Notes Receivable - Related Party

Notes Receivable - Related Party

Since December 2015, the Company has entered into ten promissory note agreements with Fortis with aggregate principal amounts of $26,344,883. The notes receivable bear interest at an annual rate of 3% and mature on December 31, 2017. As of July 31, 2017, and April 31, 2017, the outstanding balance of the notes receivable was $26,344,883 and $24,786,382, respectively.

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Interest in Real Estate Rights

3 Months Ended

Jul. 31, 2017

Notes to Financial Statements

Interest in Real Estate Rights

As discussed in Note 5, MegaWest received an interest in real estate rights of 30 condominium units from Fortis pursuant to the MegaWest Transaction.  For the three months ended July 31, 2017, the Company recognized a net gain of $271,490 related to the sale of one condominium unit by Fortis.

The following table summarizes the activity for interest in real estate rights:

	Three Months Ended July 31, 2017
Balance at April 30, 2017	$	309,860
Cost of sales – one condominium unit		(309,860	)
Balance at July 31, 2017	$	-

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Oil and Gas Assets

3 Months Ended

Jul. 31, 2017

Extractive Industries [Abstract]

Oil and Gas Assets

The following table summarizes the activity of the oil and gas assets by project for the three months ended July 31, 2017:

	Oklahoma			Larne Basin		Other (1)		Total
Balance May 1, 2017	$	1,232,192		$	761,444	$	100,000	$	2,093,636
Additions		744,464			-		-		744,464
Disposals		-			-		-		-
Depreciation, depletion and amortization		(5,959	)		-		-		(5,959	)
Impairment of oil and gas assets		-			-		-		-
Balance July 31, 2017	$	1,970,697		$	761,444	$	100,000	$	2,832,141

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2017, and April 30, 2017, management concluded that impairment was not necessary as all other assets were carried at salvage value.

Kern County Project.  On March 4, 2016, the Company executed an Asset Purchase and Sale and Exploration Agreement to acquire a 13.75% working interest in certain oil and gas leases located in southern Kern County, California. Horizon Energy also purchased a 27.5% working interest in the project.

Under the terms of the agreement, the Company paid $108,333 to the sellers on the closing date, and is obligated to pay certain other costs and expenses after the closing date related to existing and new leases as more particularly set forth in the agreement. As of April 30, 2016, exploratory activity had not commenced and the $108,333 was recorded as prepaid oil and gas development costs on the consolidated balance sheet. In addition, the sellers are entitled to an overriding royalty interest in certain existing and new leases acquired after the closing date, and the Company is required to make certain other payments, each in amounts set forth in the agreement.

Acquisition of Interest in Larne Basin.  On January 19, 2016, Petro River UK Limited, ("Petro UK"), a wholly owned subsidiary of the Company, entered into a Farmout Agreement to acquire a 9% interest in Petroleum License PL 1/10 and P2123 (the “Larne Licenses”) located in the Larne Basin in Northern Ireland (the "Larne Transaction").  The two Larne Licenses, one onshore and one offshore, together encompass approximately 130,000 acres covering the large majority of the prospective Larne Basin.  The other parties to the Farmout Agreement are Southwestern Resources Ltd, a wholly owned subsidiary of Horizon Energy, which will acquire a 16% interest, and Brigantes Energy Limited, which will retain a 10% interest.  Third parties will own the remaining 65% interest.

Under the terms of the Farmout Agreement, Petro UK deposited approximately $735,000 into an escrow agreement ("Escrow Agreement"), which amount represented Petro UK's obligation to fund the total projected cost to drill the first well under the terms of the Farmout Agreement. As of July 31, 2016, development of the first well had not commenced and the escrow payment was recorded as prepaid oil and gas development costs on the consolidated balance sheet.The total deposited amount to fund the cost to drill the first well is approximately $6,159,452, based on an exchange rate of one British Pound for 1.44 U.S. Dollars. Petro UK was and will continue to be responsible for its pro-rata costs of additional wells drilled under the Farmout Agreement. Drilling of the first well was completed in June 2016.

Oklahoma Properties. During the three months ended July 31, 2017, the Company paid approximately $739,500 and $5,000 for proven and unproven oil and gas assets, respectively.

Divestiture of Kansas Properties. On December 23, 2015, Petro River Oil, LLC ("Petro LLC"), a wholly owned subsidiary of MegaWest, divested various interests in oil and gas leases, wells, records, data and related personal property located along the Mississippi Lime play in the state of Kansas, which assets were acquired by Petro LLC in 2012. In connection with the divestiture, the assignee and purchaser of the interests agreed to pay outstanding liabilities, including unpaid taxes, and assume certain responsibilities to plug any abandoned wells. No cash consideration was paid for the interests.  The Company recorded a loss of $7,519,460 in connection with the divestiture of these oil and gas properties, representing the $7,727,287 oil and gas assets book value, partially offset by the asset retirement obligation liability. MegaWest is a 58.51% owned subsidiary of the Company following consummation of the MegaWest Transaction, defined above.

Impairment of Oil & Gas Properties. As of July 31, 2017, the Company assessed its oil and gas assets for impairment and did not recognized a charge related to its oil and gas property. As of April 30, 2017, the Company assessed its oil and gas assets for impairment and recognized a charge of $20,942 related to the Oklahoma oil and gas property.

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Asset Retirement Obligations

3 Months Ended

Jul. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The total future asset retirement obligations were estimated based on the Company’s ownership interest in all wells and facilities, the estimated legal obligations required to retire, dismantle, abandon and reclaim the wells and facilities and the estimated timing of such payments. The Company estimated the present value of its asset retirement obligations at both July 31, 2017 and April 30, 2017, based on a future undiscounted liability of $648,848 and $573,069, respectively. These costs are expected to be incurred within one to 24 years. A credit-adjusted risk-free discount rate of 10% and an inflation rate of 2% were used to calculate the present value.

Changes to the asset retirement obligations were as follows:

	Three Months Ended July 31, 2017			Three Months Ended July 31, 2016
Balance, beginning of period	$	558,696		$	763,062
Additions		7,500			-
Disposals		-			(216,580	)
Accretion		2,971			4,207
		569,167			550,689
Less: Current portion for cash flows expected to be incurred within one year		(406,403	)		(406,403	)
Long-term portion, end of period	$	162,764		$	144,286

Expected timing of asset retirement obligations:

Year Ending April 30,
2018 (remainder of year)	$	406,403
2019		-
2020		-
2021		-
2022		-
Thereafter		242,445
Subtotal		648,848
Effect of discount		(79,681	)
Total	$	569,167

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Related Party Transactions

3 Months Ended

Jul. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Employment Agreements

On October 30, 2015, Mr. Stephen Brunner joined the Company as President.  Mr. Brunner has been tasked with making oil and gas related decisions and executing the Company’s growth strategy. Under the terms of the contract, Mr. Brunner receives a base salary of $10,000 per month. Mr. Brunner was also granted 53,244 stock options. He also has the right to purchase an additional 1.75% of the Company’s common stock subject to shareholder approval on the increase of the current stock option plan and achieving pre-defined target objectives.

The Company computed the fair value of the grant as of the date of grant utilizing a Black-Scholes option-pricing model using the following assumptions: common share value based on the fair value of the Company’s common stock as quoted on the Over the Counter Bulletin Board, $1.78; exercise price of $2.00; expected volatility of 171%; and a discount rate of 2.16%. The grant date fair value of the award was $89,525. For the three months ended July 31, 2017 and 2016, the Company expensed $6,101 and $6,101, respectively, to general and administrative expenses. 

MegaWest Transaction

On October 15, 2015, the Company entered into the Contribution Agreement with MegaWest and Fortis, pursuant to which the Company and Fortis each agreed to contribute certain assets to MegaWest in exchange for shares of MegaWest common stock. See Note 5 above.

Accounts Receivable - Related Party

As discussed in Note 5 above, on October 15, 2015, the Company entered into the Contribution Agreement with MegaWest and Fortis pursuant to which the Company and Fortis each agreed to assign certain assets to MegaWest in exchange for the MegaWest Shares.

Upon execution of the Contribution Agreement, Fortis transferred certain indirect interests held in 30 condominium units and the rights to any profits and proceeds therefrom, with its basis of $15,544,382, to MegaWest. As of July 31, 2017 and April 30, 2017, the Company had an accounts receivable – related party in the amount of $1,146,673 and $2,123,175, respectively, which was due from Fortis for the profits belonging to MegaWest. See Note 5 above.  

Notes Receivable – Related Party

As discussed in Note 6, the Company entered into ten promissory note agreements with Fortis, with total principal amount of $26,344,883 as of July 31, 2017. The notes receivable bear interest at an annual interest rate of 3% and mature on December 31, 2017. For the three months ended July 31, 2017, the Company recorded $194,599 of interest income on the notes receivable. As of July 31, 2017, and April 30, 2017, the outstanding balance of the notes receivable was $26,344,883 and $24,786,382, respectively.

Notes Payable – Related Party

On December 1, 2015, the Company issued a non-recourse promissory note, in the principal amount of $750,000 to Horizon Investments (“Note A”), the proceeds of which were to be used for working capital purposes. Interest on Note A was due upon the earlier to occur of closing of the Horizon Transaction, or December 31, 2016. Amounts due under the terms of Note A accrued interest at an annual rate equal to one half of one percent.

On December 7, 2015, the Company entered into the Horizon Transaction, pursuant to which the Company executed a purchase agreement to acquire Horizon Investments in an all-stock deal. See Note 4. Mr. Scot Cohen, the Company’s Executive Chairman, is the sole Manager of Horizon Investments. In addition, Mr. Cohen owns a 9.2% membership interest in Horizon Investments. Horizon Investments owns a 20% interest in Horizon Energy Partners.  Mr. Cohen owns a 2.8% membership interest in Horizon Energy Partners.

On January 13, 2016, the Company issued a second non-recourse promissory note in the principal amount of $750,000 ("Note B") to Horizon Investments. All of the proceeds from Note B were used to fund Petro UK's obligations under the terms of the Farmout Agreement, and were deposited into the Escrow Agreement. The principal and all accrued and unpaid interest on Note B was due upon the earlier to occur of closing of the transactions contemplated under the terms of the Purchase Agreement. Amounts due under the terms of Note B accrued interest at an annual rate equal to one half of one percent.

On April 7, 2016, the Company issued a third non-recourse promissory note in the principal amount of $100,000 ("Note C") to Horizon Investments. All of the proceeds from Note C were used to fund working capital requirements. The principal and all accrued and unpaid interest on Note C was due upon the earlier to occur of closing of the transactions contemplated under the terms of the Purchase Agreement. Amounts due under the terms of Note C accrued interest at an annual rate equal to one half of one percent.

Upon consummation of the Horizon Transaction on May 3, 2016, each of Note A, Note B and Note C were paid off in full.

$2.0 Million Secured Note Financing

Scot Cohen, a member of the Company’s Board of Directors and a substantial stockholder of the Company, owns or controls 31.25% of Funding Corp., the holder of the Secured Note issued by the Company in June 2017 in the principal amount of $2.0 million. The Secured Note accrues interest at a rate of 10% per annum, and matures on June 30, 2020. (See Note 1). The Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

Pursuant to the financing agreement, the Company issued to Funding Corp. a warrant to purchase 840,336 shares of the Company’s common stock. Upon issuance of the note, the Company valued the warrants at the grant date share price of $2.38 and recorded $952,056 to debt discount on the consolidated balance sheet. The debt discount is amortized over the earlier of (i) the term of the debt or (ii) conversion of the debt, using the effective interest method. The amortization of debt discount is included as a component of interest expense in the consolidated statements of operations. There was unamortized debt discount of $914,678 as of July 31, 2017. During the three months ended July 31, 2017 and 2016, the Company recorded amortization of debt discount totaling $37,378 and $0, respectively. See Note 10 for the assumptions and inputs utilized to value the warrants granted.

As of July 31, 2017, the outstanding balance, net of debt discount, and accrued interest on the notes due to the lender was $1,085,322 and $24,476, respectively. 

As additional consideration for the purchase of the Secured Note, the Company issued to Funding Corp. the 2017 Override, which provided Funding Corp. with an overriding royalty interest equal to 2% in all production from the Company’s interest in the Company’s concessions located in Osage County, Oklahoma, currently held by Spyglass.

Purchase of 2% Overriding Royalty

On August 14, 2017, following a review of the Company’s capital requirements necessary to fund its 2017 development program, the Company’s independent directors consented to Scot Cohen’s purchase from various third parties who collectively held a 2% overriding royalty interest that originally burdened the Osage County, Oklahoma concession for $250,000 (the “Original Override”). Mr. Cohen agreed to sell the Original Override to the Company at the same price paid by him (plus market interest on his capital) upon a determination by the Company to finance the Osage County development plan on terms similar to the June 13, 2017 secured note financing.

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Equity

3 Months Ended

Jul. 31, 2017

Stockholders' Equity Note [Abstract]

Equity

As of July 31, 2017 and April 30, 2017, the Company had 5,000,000 shares of preferred stock, par value $0.00001 per share, authorized. As of July 31, 2017, and April 30, 2017, the Company had 29,500 shares of Series B Preferred Stock, par value $0.00001 per share (“Series B Preferred”), authorized. No Series B Preferred shares are currently issued or outstanding, and no other series of preferred stock have been designated. 

As of July 31, 2017 and April 30, 2017, the Company had 150,000,000 shares of common stock, par value $0.00001 per share, authorized. During the three months ended July 31, 2017, the Company issued 12,222 shares of common stock related to a cashless exercise of 25,000 options. There were 15,840,143 and 15,827,921 shares of common stock issued and outstanding as of July 31, 2017 and April 30, 2017, respectively. 

Options

The following table summarizes information about the options changes of options for the period from April 30, 2017 to July 31, 2017 and options outstanding and exercisable at July 31, 2017:

	Options			Weighted Average Exercise Prices
Outstanding April 30, 2017		2,599,682		$	2.13
Exercisable – April 30, 2017		1,954,735			2.35
Granted		-
Exercised		(25,000	)		1.38
Forfeited/Cancelled		-
Outstanding – July 31, 2017		2,574,682			2.14
Exercisable – July 31, 2017		2,169,277		$	2.25
Outstanding – Aggregate Intrinsic Value				$	1,717,333
Exercisable – Aggregate Intrinsic Value				$	1,412,799

The following table summarizes information about the options outstanding and exercisable at July 31, 2017:

Exercise Price		Options Outstanding		Weighted Avg. Life Remaining (years)		Options Exercisable		Weighted Average Exercise Price
$	1.38		1,840,958		9.54	$	1,276,172	$	1.38
$	1.98		5,000		9.27	$	3,750	$	1.98
$	2.00		457,402		8.25	$	392,780	$	2.00
$	2.87		65,334		8.25	$	64,611	$	2.87
$	3.00		51,001		9.91	$	42,445	$	3.00
$	3.39		12,000		8.89	$	12,000	$	3.39
$	6.00		10,000		8.00	$	10,000	$	6.00
$	12.00		132,987		6.73	$	132,988	$	12.00
			2,574,682				2,169,277

The aggregate intrinsic value of the outstanding options was $1,717,333. 

During the three months ended July 31, 2017 and 2016, the Company expensed $529,332 and $1,150,197, respectively, related to the vesting of outstanding options to general and administrative expense for stock-based compensation pursuant to employment and consulting agreements. 

As of July 31, 2017, the Company has approximately $972,397 in unrecognized stock-based compensation expense related to unvested options, which will be amortized over a weighted average exercise period of approximately 3.00 years.

Warrants

The fair value of the 840,336 warrants granted in conjunction with the $2.0 Million Secured Note (as discussed in Note 9) were estimated on the date of grant using the Black-Scholes option-pricing model.

The assumptions used for the warrants granted during the three months ended July 31, 2017 are as follows:

	June 30, 2017
Exercise price		$	2.38
Expected dividends			0	%
Expected volatility			169.63	%
Risk free interest rate			1.49	%
Expected life of warrant			3 years

The following is a summary of the Company’s warrant activity:

	Number of Warrants		Weighted Average Exercise Price		Weighted Average Life Remaining
Outstanding and exercisable – April 30, 2017		133,333	$	50.00		2.83
Forfeited		-		-		-
Granted		840,336		2.05		2.48
Outstanding and exercisable – July 31, 2017		973,669		8.90		2.84

The aggregate intrinsic value of the outstanding warrants was $0.

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Non-Controlling Interest

3 Months Ended

Jul. 31, 2017

Noncontrolling Interest [Abstract]

Non-Controlling Interest

For the three months ended July 31, 2017, the changes in the Company’s non–controlling interest were as follows:

	Bandolier			Fortis		Total
Non–controlling interest at April 30, 2017	$	(699,873	)	$	13,310,343	$	12,610,470
Contribution of cash by non-controlling interest holders		-			-		-
Non–controlling interest share of income (losses)		(36,574	)		111,145		74,571
Non–controlling interest at July 31, 2017	$	(736,447	)	$	13,421,488	$	12,685,041

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Contingency and Contractual Obligations

3 Months Ended

Jul. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Contingency and Contractual Obligations

Pending Litigation.

(a) In January 2010, the Company experienced a flood in its Calgary office premises as a result of a broken water pipe. There was significant damage to the premises rendering them unusable until the landlord had completed remediation. Pursuant to the lease contract, the Company asserted that rent should be abated during the remediation process and accordingly, the Company did not pay any rent after December 2009. During the remediation process, the Company engaged an independent environmental testing company to test for air quality and for the existence of other potentially hazardous conditions. The testing revealed the existence of potentially hazardous mold and the consultant provided specific written instructions for the effective remediation of the premises. During the remediation process, the landlord did not follow the consultant’s instructions and correct the potentially hazardous mold situation and subsequently in June 2010 gave notice and declared the premises to be ready for occupancy. The Company re-engaged the consultant to re-test the premises and the testing results again revealed the presence of potentially hazardous mold. The Company determined that the premises were not fit for re-occupancy and considered the landlord to be in default of the lease. The Landlord subsequently terminated the lease.

On January 30, 2014, the landlord filed a Statement of Claim against the Company for rental arrears in the amount aggregating CAD $759,000 (approximately USD $625,000 as of September 13, 2017). The Company filed a defense and on October 20, 2014, it filed a summary judgment application stating that the landlord’s claim is barred as it was commenced outside the 2-year statute of limitation period under the Alberta Limitations Act. The landlord subsequently filed a cross-application to amend its Statement of Claim to add a claim for loss of prospective rent in an amount of CAD $665,000 (approximately USD $548,000 as of September 13, 2017). The applications were heard on June 25, 2015 and the court allowed both the Company’s summary judgment application and the landlord’s amendment application.  Both of these orders were appealed though two levels of the Alberta courts and the appeals were dismissed at both levels. The net effect is that the landlord's claim for loss of prospective rent is to proceed.

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Commission”) that the Company was not in compliance with regulations promulgated by the Commission. The Company was therefore deemed to have lost its corporate privileges within the State of Texas and as a result, all wells within the state would have to be plugged. The Commission therefore collected $25,000 from the Company, which was originally deposited with the Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Commission also reserved its right to separately seek any remedies against the Company resulting from its noncompliance.

(c) On August 11, 2014, Martha Donelson and John Friend amended their complaint in an existing lawsuit by filing a class action complaint styled: Martha Donelson and John Friend, et al. v. United States of America, Department of the Interior, Bureau of Indian Affairs and Devon Energy Production, LP, et al., Case No. 14-CV-316-JHP-TLW, United States District Court for the Northern District of Oklahoma (the “Proceeding”).  The plaintiffs added as defendants twenty-seven (27) specifically named operators, including Spyglass, as well as all Osage County lessees and operators who have obtained a concession agreement, lease or drilling permit approved by the Bureau of Indian Affairs (“BIA”) in Osage County allegedly in violation of National Environmental Policy Act (“NEPA”).  Plaintiffs seek a declaratory judgment that the BIA improperly approved oil and gas leases, concession agreements and drilling permits prior to August 12, 2014, without satisfying the BIA’s obligations under federal regulations or NEPA, and seek a determination that such oil and gas leases, concession agreements and drilling permits are void ab initio.  Plaintiffs are seeking damages against the defendants for alleged nuisance, trespass, negligence and unjust enrichment.  The potential consequences of such complaint could jeopardize the corresponding leases.

On October 7, 2014, Spyglass, along with other defendants, filed a Motion to Dismiss the August 11, 2014 Amended Complaint on various procedural and legal grounds. Following the significant briefing, the Court, on March 31, 2016, granted the Motion to Dismiss as to all defendants and entered a judgment in favor of the defendants against the plaintiffs. On April 14, 2016, Spyglass with the other defendants, filed a Motion seeking its attorneys’ fees and costs. The motion remains pending. On April 28, 2016, the plaintiffs filed three motions: a Motion to Amend or Alter the Judgment; a Motion to Amend the Complaint; and a Motion to Vacate Order. On November 23, 2016, the Court denied all three of Plaintiffs’ motions.  On December 6, 2016, Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals.  That appeal is pending as of the effective date of this response. There is no specific timeline by which the Court of Appeals must render a ruling. Spyglass intends to continue to vigorously defend its interest in this matter. 

(d) MegaWest Energy Missouri Corp. (“MegaWest Missouri”), a wholly owned subsidiary of the Company, is involved in two cases related to oil leases in West Central, Missouri.  The first case (James Long and Jodeane Long v. MegaWest Energy Missouri and Petro River Oil Corp., case number 13B4-CV00019) is a case for unlawful detainer, pursuant to which the plaintiffs contend that MegaWest Missouri oil and gas lease has expired and MegaWest Missouri is unlawfully possessing the plaintiffs’ real property by asserting that the leases remain in effect.  The case was originally filed in Vernon County, Missouri on September 20, 2013.  MegaWest Missouri filed an Answer and Counterclaims on November 26, 2013 and the plaintiffs filed a motion to dismiss the counterclaims. MegaWest Missouri filed a motion for Change of Judge and Change of Venue and the case was transferred to Barton County.  The court granted the motion to dismiss the counterclaims on February 3, 2014.  As to the other allegations in the complaint, the matter is still pending.

MegaWest Missouri filed a second case on October 14, 2014 (MegaWest Energy Missouri Corp. v. James Long, Jodeane Long, and Arrow Mines LLC, case number 14VE-CV00599).  This case is pending in Vernon County, Missouri.  Although the two cases are separate, they are interrelated.  In the Vernon County case, MegaWest Missouri has made claims for: (1) replevin for personal property; (2) conversion of personal property; (3) breach of the covenant of quiet enjoyment regarding the lease; (4) constructive eviction of the lease; (5) breach of fiduciary obligation against James Long; (6) declaratory judgment that the oil and gas lease did not terminate; and (7) injunctive relief to enjoin the action pending in Barton County, Missouri.  The plaintiffs filed a motion to dismiss on November 4, 2014, and Arrow Mines, LLC filed a motion to dismiss on November 13, 2014.  Both motions remain pending, and MegaWest Missouri will file an opposition to the motions in the near future. 

The Company is from time to time involved in legal proceedings in the ordinary course of business. It does not believe that any of these claims and proceedings against it is likely to have, individually or in the aggregate, a material adverse effect on its financial condition or results of operations.

Redetermination of Bandolier Interest.

In connection with the Contribution Agreement, entered into by and between the Company, MegaWest and Fortis (see Note 5), the parties agreed to the Redetermination of the fair market value of the Bandolier Interest at any time following the six-month anniversary after the execution thereof.  Upon a Redetermination, which has not occurred as of September 14, 2017, but is anticipated prior to December 31, 2017, in the event there is a shortfall from the valuation ascribed to the Bandolier Interest at the time of the Redetermination, as compared to the value ascribed to the Bandolier Interest in the Contribution Agreement, the Company will be required to provide Fortis with a cash payment in an amount equal to the shortfall.  If the Company is unable to deliver to Fortis the cash payment required after the Redetermination, if any, the board of directors of MegaWest shall have the right to exercise certain remedies against the Company, including a right to foreclose on the Company’s entire equity in MegaWest, which equity interest has been pledged to Fortis under the terms of the Contribution Agreement.  In the event of foreclosure, the Bandolier Interest would revert back to the Company, and the Company would record a loss for the amount of the notes receivable, interest in real estate rights, accounts receivable – related party, and any accrued interest.

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Subsequent Events

3 Months Ended

Jul. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were available to be issued. Based on this evaluation, the Company has identified no reportable subsequent events other than those disclosed below or elsewhere in these financials.

In August 2017, the Company issued 2,923 shares of common stock related to a cashless exercise of 10,000 options.

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Significant Accounting Policies (Policies)

3 Months Ended

Jul. 31, 2017

Accounting Policies [Abstract]

Use of Estimates

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

The Company’s financial statements are based on a number of significant estimates, including oil and natural gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and natural gas properties, and timing and costs associated with its asset retirement obligations, as well as those related to the fair value of stock options, stock warrants and stock issued for services. While we believe that our estimates and assumptions used in preparation of the financial statements are appropriate, actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include all highly liquid monetary instruments with original maturities of three months or less when purchased. These investments are carried at cost, which approximates fair value. Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash deposits. The Company maintains its cash in institutions insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, the Company’s cash and cash equivalent balances may be uninsured or in amounts that exceed the FDIC insurance limits. At July 31, 2017, approximately $788,831 of the Company’s cash balances were uninsured. The Company has not experienced any loses on such accounts.

Receivables

Receivables that management has the intent and ability to hold for the foreseeable future are reported in the balance sheet at outstanding principal adjusted for any charge-offs and the allowance for doubtful accounts. Losses from uncollectible receivables are accrued when both of the following conditions are met: (a) Information available before the financial statements are issued or are available to be issued indicates that it is probable that an asset has been impaired at the date of the financial statements, and (b) The amount of the loss can be reasonably estimated. These conditions may be considered in relation to individual receivables or in relation to groups of similar types of receivables. If the conditions are met, an accrual shall be made even though the particular receivables that are uncollectible may not be identifiable. The Company reviews individually each receivable for collectability and performs on-going credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current credit worthiness, as determined by the review of their current credit information; and determines the allowance for doubtful accounts based on historical write-off experience, customer specific facts and general economic conditions that may affect a client’s ability to pay. Bad debt expense is included in general and administrative expenses, if any.

Credit losses for receivables (uncollectible receivables), which may be for all or part of a particular receivable, shall be deducted from the allowance. The related receivable balance shall be charged off in the period in which the receivables are deemed uncollectible. Recoveries of receivables previously charged off shall be recorded when received. The Company charges off its account receivables against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

The allowance for doubtful accounts at July 31, 2017 and April 30, 2017 was $0.

Interest in Real Estate Rights

Interest in real estate rights contributed by Fortis related to real properties that Fortis plans to sell within one year. Since these properties are contributed by Fortis, a related party, the rights are stated on balance sheet at the cost basis of Fortis.

Oil and Gas Operations

Oil and Gas Properties: The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the costs of both successful and unsuccessful exploration and development activities are capitalized as oil and gas property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country, in which case a gain or loss would be recognized in the consolidated statements of operations. All of the Company’s oil and gas properties are located within the continental United States, its sole cost center.

Oil and gas properties may include costs that are excluded from costs being depleted. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and in process exploration drilling costs. All costs excluded are reviewed at least annually to determine if impairment has occurred.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate. For the three months ended July 31, 2017, the Company evaluated and recorded no impairment on these properties.

Proved Oil and Gas Reserves: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. All of the Company’s oil and gas properties with proven reserves were impaired to the salvage value prior to the Bandolier transaction. The price used to establish economic producibility is the average price during the 12-month period preceding the end of the entity’s fiscal year and calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within such 12-month period. For the three months ended July 31, 2017, the Company did not record an impairment charge on its proved oil and gas properties.

Depletion, Depreciation and Amortization: Depletion, depreciation and amortization is provided using the unit-of-production method based upon estimates of proved oil and gas reserves with oil and gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is deducted from the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. 

In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by the Company’s geologists and engineers which require significant judgment, as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expenses. There have been no material changes in the methodology used by the Company in calculating depletion, depreciation and amortization of oil and gas properties under the full cost method during the three months ended July 31, 2017 and 2016.  

Investments - Cost Method and Equity Method

Investments held in stock of entities other than subsidiaries, namely corporate joint ventures and other non-controlled entities usually are accounted for by one of three methods: (i) the fair value method, (ii) the equity method, or (iii) the cost method. The equity method tends to be most appropriate if an investment enables the investor to influence the operating or financial policies of the investee. The cost basis is utilized for investments that are less than 20% owned, and the Company does not exercise significant influence over the operating and financial policies of the investee. Under the cost method, investments are held at historical cost.

Fair Value of Financial Instruments

The Company follows paragraph 825-10-50-10 of the FASB Accounting Standards Codification for disclosures about fair value of its financial instruments and paragraph 820-10-35-37 of the FASB Accounting Standards Codification (“Paragraph 820-10-35-37”) to measure the fair value of its financial instruments. Paragraph 820-10-35-37 establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, Paragraph 820-10-35-37 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by Paragraph 820-10-35-37 are described below:

Level 1	Quoted market prices available in active markets for identical assets or liabilities as of the reporting date.
Level 2	Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3	Pricing inputs that are generally observable inputs and not corroborated by market data.

Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable.

The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

The carrying amount of the Company’s financial assets and liabilities, such as cash, prepaid expenses, and accounts payable and accrued liabilities approximate their fair value because of the short maturity of those instruments.

Transactions involving related parties cannot be presumed to be carried out on an arm’s-length basis, as the requisite conditions of competitive, free-market dealings may not exist. Representations about transactions with related parties, if made, shall not imply that the related party transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions unless such representations can be substantiated.

Stock-Based Compensation

Generally, all forms of stock-based compensation, including stock option grants, warrants, and restricted stock grants are measured at their fair value utilizing an option pricing model on the award’s grant date, based on the estimated number of awards that are ultimately expected to vest.

Under fair value recognition provisions, the Company recognizes equity–based compensation net of an estimated forfeiture rate and recognizes compensation cost only for those shares expected to vest over the requisite service period of the award.

The fair value of option award is estimated on the date of grant using the Black–Scholes option valuation model. The Black–Scholes option valuation model requires the development of assumptions that are input into the model. These assumptions are the expected stock volatility, the risk–free interest rate, the option’s expected life, the dividend yield on the underlying stock and the expected forfeiture rate. Expected volatility is calculated based on the historical volatility of the Company’s common stock over the expected option life and other appropriate factors. Risk–free interest rates are calculated based on continuously compounded risk–free rates for the appropriate term. The dividend yield is assumed to be zero as the Company has never paid or declared any cash dividends on its common stock and does not intend to pay dividends on the common stock in the foreseeable future. The expected forfeiture rate is estimated based on historical experience.

Determining the appropriate fair value model and calculating the fair value of equity–based payment awards requires the input of the subjective assumptions described above. The assumptions used in calculating the fair value of equity–based payment awards represent management’s best estimates, which involve inherent uncertainties and the application of management’s judgment. As a result, if factors change and the Company uses different assumptions, the equity–based compensation expense could be materially different in the future. In addition, the Company is required to estimate the expected forfeiture rate and recognize expense only for those shares expected to vest. If the actual forfeiture rate is materially different from our estimate, the equity–based compensation expense could be significantly different from what the Company has recorded in the current period. 

The Company determines the fair value of the stock–based payments to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.  If the fair value of the equity instruments issued is used, it is measured using the stock price and other measurement assumptions as of the earlier of either (1) the date at which a commitment for performance by the counterparty to earn the equity instruments is reached, or (2) the date at which the counterparty’s performance is complete.

The expenses resulting from stock-based compensation are recorded as general and administrative expenses in the consolidated statement of operations, depending on the nature of the services provided.

Income Taxes

Income Tax Provision

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance to the extent management concludes it is more likely than not that the assets will not be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the statements of operations in the period that includes the enactment date.

The Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent (50%) likelihood of being realized upon ultimate settlement.

The estimated future tax effects of temporary differences between the tax basis of assets and liabilities are reported in the accompanying consolidated balance sheets, as well as tax credit carry-backs and carry-forwards. The Company periodically reviews the recoverability of deferred tax assets recorded on its consolidated balance sheets and provides valuation allowances as management deems necessary.

Management makes judgments as to the interpretation of the tax laws that might be challenged upon an audit and cause changes to previous estimates of tax liability. In addition, the Company operates within multiple taxing jurisdictions and is subject to audit in these jurisdictions. In management’s opinion, adequate provisions for income taxes have been made for all years. If actual taxable income by tax jurisdiction varies from estimates, additional allowances or reversals of reserves may be necessary.

Uncertain Tax Positions

The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard, or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained.

At July 31, 2017 and April 30, 2017, the Company had approximately $3,640,928 and $3,442,724, respectively, of liabilities for uncertain tax positions. Interpretation of taxation rules relating to net operating loss utilization in real estate transactions give rise to uncertain positions. In connection with the uncertain tax position, there were no interest or penalties recorded as the position is expected but the tax returns are not yet due.

The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results.

The number of years with open tax audits varies depending on the tax jurisdiction. The Company’s major taxing jurisdictions include the United States (including applicable states).

Per Share Amounts

Basic net income (loss) per common share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. For the three months ended July 31, 2017 and 2016, potentially dilutive securities were not included in the calculation of diluted net loss per share because to do so would be anti-dilutive.

The Company had the following common stock equivalents at July 31, 2017 and 2016:

	July 31, 2017		July 31, 2016
Stock Options		2,574,682		2,502,182
Stock Purchase Warrants		973,669		133,333
Total		3,548,351		2,635,515

Recent Accounting Pronouncements

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard’s core principle (issued as ASU 2014-09 by the FASB), is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. These may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The new guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU 2014-09 by one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. This ASU is effective for public reporting companies for interim and annual periods beginning after December 15, 2017. The Company is currently evaluating its adoption method and the impact of the standard on its consolidated financial statements and has not yet determined the method by which the Company will adopt the standard in 2017.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing” (Topic 606). In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross verses Net)” (Topic 606). These amendments provide additional clarification and implementation guidance on the previously issued ASU 2014-09, “Revenue from Contracts with Customers”. The amendments in ASU 2016-10 provide clarifying guidance on materiality of performance obligations; evaluating distinct performance obligations; treatment of shipping and handling costs; and determining whether an entity's promise to grant a license provides a customer with either a right to use an entity's intellectual property or a right to access an entity's intellectual property. The amendments in ASU 2016-08 clarify how an entity should identify the specified good or service for the principal versus agent evaluation and how it should apply the control principle to certain types of arrangements. The adoption of ASU 2016-10 and ASU 2016-08 is to coincide with an entity's adoption of ASU 2014-09, which we intend to adopt for interim and annual reporting periods beginning after December 15, 2017. The Company is currently evaluating the impact of the new standard.

In April 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation” (Topic 718). The FASB issued this update to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. The updated guidance is effective for annual periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption of the update is permitted. The Company is currently evaluating the impact of the new standard.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”). ASU 2016-15 will make eight targeted changes to how cash receipts and cash payments are presented and classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017. The new standard will require adoption on a retrospective basis unless it is impracticable to apply, in which case it would be required to apply the amendments prospectively as of the earliest date practicable. The Company is currently in the process of evaluating the impact of ASU 2016-15 on its consolidated financial statements. 

The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations, or cash flows. 

Subsequent Events

The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration. 

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Significant Accounting Policies (Tables)

3 Months Ended

Jul. 31, 2017

Accounting Policies [Abstract]

Schedule of Common Stock Equivalents

	July 31, 2017		July 31, 2016
Stock Options		2,574,682		2,502,182
Stock Purchase Warrants		973,669		133,333
Total		3,548,351		2,635,515

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Interest in Real Estate Rights (Tables)

3 Months Ended

Jul. 31, 2017

Notes to Financial Statements

Real estate held for sale

	Three Months Ended July 31, 2017
Balance at April 30, 2017	$	309,860
Cost of sales – one condominium unit		(309,860	)
Balance at July 31, 2017	$	-

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Oil and Gas Assets (Tables)

3 Months Ended

Jul. 31, 2017

Extractive Industries [Abstract]

Schedule of Oil and Gas Assets

	Oklahoma			Larne Basin		Other (1)		Total
Balance May 1, 2017	$	1,232,192		$	761,444	$	100,000	$	2,093,636
Additions		744,464			-		-		744,464
Disposals		-			-		-		-
Depreciation, depletion and amortization		(5,959	)		-		-		(5,959	)
Impairment of oil and gas assets		-			-		-		-
Balance July 31, 2017	$	1,970,697		$	761,444	$	100,000	$	2,832,141

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2017, and April 30, 2017, management concluded that impairment was not necessary as all other assets were carried at salvage value.

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Asset Retirement Obligations (Tables)

3 Months Ended

Jul. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes to Asset Retirement Obligation

	Three Months Ended July 31, 2017			Three Months Ended July 31, 2016
Balance, beginning of period	$	558,696		$	763,062
Additions		7,500			-
Disposals		-			(216,580	)
Accretion		2,971			4,207
		569,167			550,689
Less: Current portion for cash flows expected to be incurred within one year		(406,403	)		(406,403	)
Long-term portion, end of period	$	162,764		$	144,286

Schedule of Expected Timing of Asset Retirement Obligations

Year Ending April 30,
2018 (remainder of year)	$	406,403
2019		-
2020		-
2021		-
2022		-
Thereafter		242,445
Subtotal		648,848
Effect of discount		(79,681	)
Total	$	569,167

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Equity (Tables)

3 Months Ended

Jul. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Changes in Stock Options

	Options			Weighted Average Exercise Prices
Outstanding April 30, 2017		2,599,682		$	2.13
Exercisable – April 30, 2017		1,954,735			2.35
Granted		-
Exercised		(25,000	)		1.38
Forfeited/Cancelled		-
Outstanding – July 31, 2017		2,574,682			2.14
Exercisable – July 31, 2017		2,169,277		$	2.25
Outstanding – Aggregate Intrinsic Value				$	1,717,333
Exercisable – Aggregate Intrinsic Value				$	1,389,626

Summary of Options Outstanding and Exercisable

Exercise Price		Options Outstanding		Weighted Avg. Life Remaining (years)		Options Exercisable		Weighted Average Exercise Price
$	1.38		1,840,958		9.54	$	1,276,172	$	1.38
$	1.98		5,000		9.27	$	3,750	$	1.98
$	2.00		457,402		8.25	$	392,780	$	2.00
$	2.87		65,334		8.25	$	64,611	$	2.87
$	3.00		51,001		9.91	$	42,445	$	3.00
$	3.39		12,000		8.89	$	12,000	$	3.39
$	6.00		10,000		8.00	$	10,000	$	6.00
$	12.00		132,987		6.73	$	132,988	$	12.00
			2,574,682				2,169,277

Schedule of warrant assumptions

	June 30, 2017
Exercise price	$	2.38
Expected dividends		0	%
Expected volatility		169.63	%
Risk free interest rate		1.49	%
Expected life of warrant		3 years

Summary of Warrants Outstanding and Exercisable

	Number of Warrants		Weighted Average Exercise Price		Weighted Average Life Remaining
Outstanding and exercisable – April 30, 2017		133,333	$	50.00		2.83
Forfeited		-		-		-
Granted		840,336		2.05		2.48
Outstanding and exercisable – July 31, 2017		973,669		8.90		2.84

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Non-Controlling Interest (Tables)

3 Months Ended

Jul. 31, 2017

Noncontrolling Interest [Abstract]

Non-controlling interest

	Bandolier			Fortis		Total
Non–controlling interest at April 30, 2017	$	(699,873	)	$	13,310,343	$	12,610,470
Contribution of cash by non-controlling interest holders		-			-		-
Non–controlling interest share of income (losses)		(36,574	)		111,145		74,571
Non–controlling interest at July 31, 2017	$	(736,447	)	$	13,421,488	$	12,685,041

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Organization (Details Narrative)	Jul. 31, 2017
Horizon Energy [Member]
Equity ownership	20.00%

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Basis of Preparation (Details Narrative)	Jul. 31, 2017
MegaWest [Member]
Equity ownership	58.51%
Bandolier [Member]
Equity ownership	50.00%

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Significant Accounting Policies - Schedule of Common Stock Equivalents (Details) - shares	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016
Common stock equivalent shares	3,548,351	2,635,515
Stock Options [Member]
Common stock equivalent shares	2,574,682	2,502,182
Stock Purchase Warrants [Member]
Common stock equivalent shares	973,669	133,333

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Significant Accounting Policies (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2017
Accounting Policies [Abstract]
Cash balance, uninsured	$ 788,831
Allowance for doubtful accounts	0		$ 0
Impairment of proved oil and gas properties	0	$ 0
Liabilities for uncertain tax positions	$ 3,640,928		$ 3,442,724

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Accounts Receivable - Related Party (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2017
Accounting Policies [Abstract]
Net (loss) gain on real estate rights	$ 271,490	$ 300,639
Due from related party	$ 1,146,673		$ 2,123,175

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Notes Receivable - Related Party (Details Narrative) - USD ($)	Jul. 31, 2017	Apr. 30, 2017
Receivables, Other, Related Parties and Retainage [Abstract]
Notes receivable related party	$ 26,344,883	$ 24,786,382

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Interest in Real Estate Rights (Details)	3 Months Ended
	Jul. 31, 2017 USD ($)
Notes to Financial Statements
Balance at beginning of period	$ 309,860
Cost of sales - one condominium unit	(309,860)
Balance at end of period	$ 0

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Oil and Gas Assets (Details)	3 Months Ended
	Jul. 31, 2017 USD ($)
Oil and gas assets, net	$ 2,093,636
Additions	744,464
Disposals	0
Depreciation, depletion and amortization	(5,959)
Impairment of oil and gas assets	0
Oil and gas assets, net	2,832,141
Oklahoma [Member]
Oil and gas assets, net	1,232,192
Additions	744,464
Disposals	0
Depreciation, depletion and amortization	(5,959)
Impairment of oil and gas assets	0
Oil and gas assets, net	1,970,697
Larne Basin
Oil and gas assets, net	761,444
Additions	0
Disposals	0
Depreciation, depletion and amortization	0
Impairment of oil and gas assets	0
Oil and gas assets, net	761,444
Other [Member]
Oil and gas assets, net	100,000	[1]
Additions	0	[1]
Disposals	0	[1]
Depreciation, depletion and amortization	0	[1]
Impairment of oil and gas assets	0	[1]
Oil and gas assets, net	$ 100,000	[1]

[1] Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2017, and April 30, 2017, management concluded that impairment was not necessary as all other assets were carried at salvage value.

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Asset Retirement Obligations (Details) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Balance, beginning of period	$ 558,696	$ 763,062
Additions	7,500	0
Disposals	0	(216,580)
Accretion	2,971	4,207
Total asset retirement obligations	569,167	550,689
Less: Current portion for cash flows expected to be incurred within one year	(406,403)		$ (406,403)
Long-term portion, end of period	$ 162,764	$ 144,286

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Asset Retirement Obligations (Details 1) - USD ($)	Jul. 31, 2017	Apr. 30, 2017	Jul. 31, 2016	Apr. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
2018 (remainder of year)	$ 406,403
2019	0
2020	0
2021	0
2122	0
Thereafter	242,445
Subtotal	648,848	$ 573,069
Effect of discount	(79,681)
Total	$ 569,167	$ 558,696	$ 550,689	$ 763,062

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Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2017	Apr. 30, 2017
Asset Retirement Obligation, future liability	$ 648,848	$ 573,069
MinimumMember
Costs are expected to be incurred, minimum period	1 year
Maximum [Member]
Costs are expected to be incurred, minimum period	24 years

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Related Party Transactions (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2017
Related Party Transactions [Abstract]
Accounts receivable, related party	$ 1,147,455		$ 2,123,175
Note receivable	26,344,883		$ 24,786,382
Amortization of debt discount	$ 37,378	$ 0

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Equity (Details)	3 Months Ended
	Jul. 31, 2017 USD ($) $ / shares shares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options, Outstanding, beginning balance | shares	2,599,682
Number of Options, Exercisable, beginning balance | shares	1,954,735
Number of Options, Granted | shares	0
Number of Options, Exercised | shares	(25,000)
Number of Options, Forfeited/Cancelled | shares	0
Number of Options, Outstanding, ending balance | shares	2,574,682
Number of Options, Exercisable, ending balance | shares	2,169,277
Weighted Avg. Exercise Price, Outstanding | $ / shares	$ 213
Weighted Avg. Exercise Price, Exercisable | $ / shares	2.35
Weighted Avg. Exercise Price, Granted | $ / shares	0.00
Weighted Avg. Exercise Price, Exercised | $ / shares	1.38
Weighted Avg. Exercise Price, Forfeited/Cancelled | $ / shares	0.00
Weighted Avg. Exercise Price, Outstanding | $ / shares	2.14
Weighted Avg. Exercise Price, Exercisable | $ / shares	$ 2.25
Outstanding - Aggregate Intrinsic Value | $	$ 1,717,333
Exercisable - Aggregate Intrinsic Value | $	$ 1,389,626

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Equity (Details 1)	3 Months Ended
	Jul. 31, 2017 $ / shares shares
Options Outstanding	2,574,682
Options Exercisable	2,169,277
Exercise Price Range One [Member]
Exercise Price | $ / shares	$ 1.38
Options Outstanding	1,840,958
Options Outstanding, Weighted Avg. Life Remaining	9 years 6 months 14 days
Options Exercisable	1,276,172
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 1.38
Exercise Price Range Two [Member]
Exercise Price | $ / shares	$ 1.98
Options Outstanding	5,000
Options Outstanding, Weighted Avg. Life Remaining	9 years 3 months 7 days
Options Exercisable	3,750
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 1.98
Exercise Price Range Three [Member]
Exercise Price | $ / shares	$ 2.00
Options Outstanding	457,402
Options Outstanding, Weighted Avg. Life Remaining	8 years 3 months
Options Exercisable	392,780
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 2.00
Exercise Price Range Four [Member]
Exercise Price | $ / shares	$ 2.87
Options Outstanding	65,334
Options Outstanding, Weighted Avg. Life Remaining	8 years 3 months
Options Exercisable	64,611
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 2.87
Exercise Price Range Five [Member]
Exercise Price | $ / shares	$ 3.00
Options Outstanding	51,001
Options Outstanding, Weighted Avg. Life Remaining	9 years 10 months 28 days
Options Exercisable	42,445
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 3.00
Exercise Price Range Six [Member]
Exercise Price | $ / shares	$ 3.39
Options Outstanding	12,000
Options Outstanding, Weighted Avg. Life Remaining	8 years 10 months 20 days
Options Exercisable	12,000
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 3.39
Exercise Price Range Seven [Member]
Exercise Price | $ / shares	$ 6.00
Options Outstanding	10,000
Options Outstanding, Weighted Avg. Life Remaining	8 years
Options Exercisable	10,000
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 6.00
Exercise Price Range Eight [Member]
Exercise Price | $ / shares	$ 12.00
Options Outstanding	132,987
Options Outstanding, Weighted Avg. Life Remaining	6 years 8 months 23 days
Options Exercisable	132,988
Options Exercisable, Weighted Avg. Exercise Price | $ / shares	$ 12.00

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Equity (Details 2) - Stock Purchase Warrants [Member]	3 Months Ended
	Jul. 31, 2017 $ / shares
Exercise price	$ 2.38
Expected dividends	0.00%
Expected volatility	169.63%
Risk free interest rate	1.49%
Expected life of warrant	3 years

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Equity (Details 3)	3 Months Ended
	Jul. 31, 2017 $ / shares shares
Weighted Avg. Exercise Price, Granted	$ 0.00
Stock Purchase Warrants [Member]
Number of Warrants, Outstanding and exercisable, Beginning balance | shares	133,333
Number of Warrants, Forfeited | shares	0
Number of Warrants, Granted | shares	840,336
Number of Warrants, Outstanding and exercisable, Ending balance | shares	973,669
Weighted Avg. Exercise Price, Outstanding and exercisable	$ 50.00
Weighted Avg. Exercise Price, Forfeited	0.00
Weighted Avg. Exercise Price, Granted	2.38
Weighted Avg. Exercise Price, Outstanding and exercisable	$ 8.90
Weighted Avg. Life Remaining, Outstanding and exercisable, beginning	2 years 9 months 29 days
Weighted Avg. Life Remaining, Outstanding and exercisable, ending	2 years 9 months 30 days

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Equity (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2017	Jul. 31, 2016	Apr. 30, 2017
Preferred stock, shares authorized	5,000,000		5,000,000
Preferred stock, par value	$ .00001		$ 0.00001
Preferred stock, shares issued	0		0
Preferred stock, shares outstanding	0		0
Common stock, shares authorized	100,000,000		100,000,000
Common stock, par value	$ 0.00001		$ 0.00001
Common stock, shares issued	15,840,143		15,827,921
Common stock, shares outstanding	15,840,143		15,827,921
Aggregate instrinsic value, options	$ 1,717,333
Unrecognized stock based compensation expense	$ 2,972,397
Unrecognized Share-based Compensation, Period for Recognition	3 years
Aggregate intrinsic value of warrants	$ 0
General and Administrative Expense [Member]
Allocated stock based compensation expense	$ 529,332	$ 1,150,197
Preferred B Shares [Member]
Preferred stock, shares authorized	295,00.		29,500
Preferred stock, par value	$ 0.00001		$ 0.00001
Preferred stock, shares issued	0		0
Preferred stock, shares outstanding	0		0

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Non-Controlling Interest (Details)	3 Months Ended
	Jul. 31, 2017 USD ($)
Non-controlling interest at April 30, 2017	$ 12,610,470
Contribution of cash by of non-controlling interest holders	0
Non-controlling interest share of income (losses)	74,571
Non-controlling interest at July 31, 2017	12,685,041
Fortis [Member]
Non-controlling interest at April 30, 2017	(699,873)
Contribution of cash by of non-controlling interest holders	0
Non-controlling interest share of income (losses)	(36,574)
Non-controlling interest at July 31, 2017	(736,447)
Bandolier [Member]
Non-controlling interest at April 30, 2017	13,310,343
Contribution of cash by of non-controlling interest holders	0
Non-controlling interest share of income (losses)	111,145
Non-controlling interest at July 31, 2017	$ 13,421,488