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, 2018

[  ] 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 5thAvenue, Suite 1702, New York, New York 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, 2018
Common Stock, $0.00001 par value per share	17,569,809 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	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	25
Item 4.	Controls and Procedures	25
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	27
Item 3.	Default Upon Senior Securities	27
Item 4.	Mine Safety Disclosures	27
Item 5.	Other Information	27
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
Assets	July 31,	April 30,
Current Assets:	2018	2018
Cash and cash equivalents	$4,642	$47,330
Accounts receivable - oil and gas	211,154	308,099
Prepaid expense and other current assets	6,118	612
Total Current Assets	221,914	356,041
Oil and gas assets, full cost method
Costs subject to amortization, net	4,152,114	3,779,414
Costs not being amortized, net	100,000	100,000
Property, plant and equipment, net	632	822
Investment in Horizon Energy Partners	1,592,418	1,592,418
Other assets	17,133	17,133
Total Long-term Assets	5,862,297	5,489,787
Total Assets	$6,084,211	$5,845,828
Liabilities and Equity
Current Liabilities:
Accounts payable and accrued expenses	$707,874	$908,343
Accrued interest on notes payable – related party	448,996	298,581
Promissory note payable – related party	300,000	-
Redetermination liability	259,313	259,313
Asset retirement obligations, current portion	406,403	413,794
Total Current Liabilities	2,122,586	1,880,031
Long-term Liabilities:
Asset retirement obligations, net of current portion	260,221	246,345
Notes payable - related parties, net of debt discount of $1,983,051 and $2,139,250, respectively	2,516,949	2,360,750
Total Long-term Liabilities	2,777,170	2,607,095
Total Liabilities	4,899,756	4,487,126
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 - 150,000,000 authorized; par value $0.00001; 17,569,733 and 17,309,733 issued and outstanding, respectively	176	173
Additional paid-in capital	52,653,524	52,407,543
Accumulated deficit	(51,469,245)	(51,049,014)
Total Equity	1,184,455	1,358,702
Total Liabilities and Equity	$6,084,211	$5,845,828

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, 2018	July 31, 2017
Revenue
Oil and natural gas sales	$574,065	$8,803
Total Revenues	574,065	8,803
Operating Expense
Lease operating expense	77,612	18,362
Depreciation, depletion and accretion	90,547	9,120
General and administrative	506,557	992,557
Total Operating Expense	674,716	1,020,039
Operating Loss	(100,651)	(1,011,236)
Other Income (Expense)
Interest income (expense), net	(319,580)	132,745
Net gain on real estate rights	-	271,490
Total Other Income (Expense)	(319,580)	404,235
Net Loss Before Income Tax Provision	(420,231)	(607,001)
Income Tax Provision	-	198,204
Net Loss	(420,231)	(805,205)
Net Income Attributable to Non-controlling Interest	-	74,571
Net Loss Attributable to Petro River Oil Corp. and Subsidiaries	$(420,231)	$(879,776)
Loss Per Common Share - Basic and Diluted	$(0.02)	$(0.06)
Weighted Average Number of Common Shares Outstanding - Basic and Diluted	17,504,019	15,835,095

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, 2018	July 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$(420,231)	$(805,205)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	245,984	529,332
Depreciation, depletion and accretion	90,547	9,120
Amortization of debt discount	156,199	37,378
Net gain on interest in real estate rights	-	(271,490)
Deferred income tax expense	-	198,204
Changes in operating assets and liabilities:
Accounts receivable – oil and gas	96,945	(246)
Accrued interest on notes receivable – related party	-	(194,599)
Prepaid expenses and other assets	(5,506)	175,464
Accrued interest on notes payable – related party	150,415	-
Accounts payable and accrued expenses	(284,489)	256,364
Net Cash Provided by (Used in) Operating Activities	29,864	(65,678)
Cash Flows From Investing Activities:
Proceeds from the sale of interest in real estate rights	-	1,557,852
Prepaid oil and gas assets	-	(281,399)
Issuance of notes receivable – related party	-	(1,558,501)
Capitalized expenditures on oil and gas assets	(372,552)	(736,964)
Cash paid for cost method investment	-	(379,418)
Net Cash Used in Investing Activities	(372,552)	(1,398,430)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from notes payable – related party	300,000	2,000,000
Net Cash Provided by Financing Activities	300,000	2,000,000
Change in cash and cash equivalents	(42,688)	535,892
Cash and cash equivalents, beginning of period	47,330	631,232
Cash and cash equivalents, end of period	$4,642	$1,167,124
SUPPLEMENTARY CASH FLOW INFORMATION:
Cash paid during the period for:
Income taxes	$-	$34,052
Interest paid	$-	$-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Additions to asset retirement obligation from new drilling	$4,150	$7,500
Change in estimate of asset retirement obligation	$1,088	$-
Accrued oil and gas development costs	$84,020	$-
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, utilizing modern technology. 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 entering 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, including in Osage County and Kay County, Oklahoma. Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company has additional exposure to a portfolio of 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 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. Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

The Company’s prospects in Oklahoma are owned directly by the Company and indirectly through Spyglass Energy Group, LLC (“Spyglass”), a wholly owned subsidiary of Bandolier Energy, LLC (“Bandolier”). As of January 31, 2018, Bandolier became wholly-owned by the Company. Bandolier has a 75% working interest in the 87,754-acre concession in Osage County, Oklahoma. The remaining 25% working interest is held by the operator, Performance Energy, LLC.

The execution of the Company’s 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, the Company plans to continue drilling additional wells on its existing concessions, and to acquire additional high-quality oil and gas properties, primarily proved producing, and proved undeveloped reserves. The Company also intends to explore low-risk development drilling and work-over opportunities. Management is also exploring farm-in and joint venture opportunities for the Company’s oil and gas assets.

Recent Developments

Recent Oil Discoveries.

On July 24, 2018, the Company announced the successful drilling of the Arsaga 25-2 exploration well, located on its concession in Osage County, Oklahoma.

On May 22, 2018, the Company announced the discovery of a new oil field, the N. Blackland Field, in its concession in Osage County, Oklahoma, upon successfully testing of the 2-34 exploration well.

In May 2017, Bandolier discovered two new oil fields with the successful drilling of the W. Blackland 1-3 and S. Blackland 2-11 exploration wells. On December 15, 2017, the Company received permits from the Bureau of Indian Affairs to drill eight additional wells in the W. Blackland Field, which were successfully completed in April 2018. The Company has received additional permits, and is currently in the process of drilling an additional two wells. The Company’s W. Blackland concessions are currently producing, and, with the drilling of additional wells, the Company anticipates substantially increasing revenue throughout the remainder of the current fiscal year.

In addition to the Company’s current development plans, within its current 3-D seismic data, additional structures in Osage County have been identified. The Company plans to drill 13 additional wells in calendar year 2018: nine in the N. Blackland Field, three in the Arsaga structure and one in the Section 13 structure. The Company anticipates drilling these wells out of cash flows from current production of its existing wells.

Cohen Loan Agreement

On June 18, 2018, Bandolier entered into a loan agreement with Scot Cohen, the Executive Chairman of the Company (the “Cohen Loan Agreement”), pursuant to which Scot Cohen loaned the Company $300,000 at a 10% annual interest rate, due on September 30, 2018. The Cohen Loan Agreement was to provide the Company with short-term financing in connection with the Company’s drilling program in Osage County, Oklahoma.  

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2.

Going Concern and Management’s Plan

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As of July 31, 2018, the Company had an accumulated deficit of $51.5 million. The Company has incurred significant losses since its inception. These matters raise substantial doubt about the Company’s ability to continue as a going concern for the twelve months following the issuance of these financial statements. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset amounts or the classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

At July 31, 2018, the Company had working deficit of approximately $1.9 million. 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 prior to its acquisition of Bandolier. At July 31, 2018, the Company had cash and cash equivalents of approximately $5,000. The Company’s primary source of operating funds since inception has been debt and equity financings.

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. In addition, 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.

3.

Basis of Preparation

The accompanying unaudited interim consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States (“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.

As a result of the Acquisition of Membership Interest in the Osage County Concession in November 2017, Bandolier is now a wholly-owned subsidiary of the Company and the Company consolidates 100% of the financial information of Bandolier. Bandolier operates the Company’s Oklahoma oil and gas properties.

Also contained in the unaudited consolidated financial statements for the periods ending July 31, 2017 and April 30, 2018 is the financial information of MegaWest, which, prior to January 31, 2018, was 58.51% owned by the Company. The unaudited consolidated financial statements for the three months ended July 31, 2017 include the results of operations of MegaWest; however, the assets and liabilities were written off in the year ended April 30, 2018.

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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, 2018, filed with the Securities and Exchange Commission (the “SEC”) on July 30, 2018. 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, 2018, 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, 2019.

4.

Significant Accounting Policies

 (a) Use of Estimates:

The preparation of financial statements in conformity with U.S. GAAP 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 management believe that its 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. 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.

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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, 2018 and April 30, 2018 was $0.

 (d) 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.

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 Company’s acquisition of its interest in Bandolier. The price used to establish economic viability 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.

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, 2018 and 2017.  

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 (e) 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.

 (f) Revenue Recognition:

ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning May 1, 2018. Refer to Note 9 – Revenue from Contracts with Customers for additional information.

The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

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Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

 (g) 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 the Company’s 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.

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 (h) Income Taxes:

Income Tax Provision

On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. ASC 740, Accounting for Income Taxes, requires companies to recognize the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The Company’s gross deferred tax assets were revalued based on the reduction in the federal statutory tax rate from 35% to 21%. A corresponding offset has been made to the valuation allowance, and any potential other taxes arising due to the Tax Act will result in reductions to the Company’s net operating loss carryforward and valuation allowance. The Company will continue to analyze the Tax Act to assess its full effects on the Company’s financial results, including disclosures, for the Company’s fiscal year ending April 30, 2019, but the Company does not expect the Tax Act to have a material impact on the Company’s consolidated financial statements.

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.

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).

 (i) Per Share Amounts:

Basic net income (loss) per common share is computed by dividing net loss attributable to stockholders by the weighted-average number of shares of common stock 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, 2018 and 2017, 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, 2018 and 2017:

	July 31, 2018	July 31, 2017
Stock Options	2,607,385	2,574,682
Stock Purchase Warrants	2,223,669	973,669
Total	4,831,054	3,548,351

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  (j) Recent Accounting Pronouncements:

In February 2016, the FASB issued ASU 2016-02, Leases, which aims to make leasing activities more transparent and comparable and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. This ASU is effective for all interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. The Company expects to adopt ASU 2016-02 beginning May 1, 2019and is in the process of assessing the impact that this new guidance is expected to have on the Company’s financial statements and related disclosures.

In September 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. ASU 2016-13 was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. ASU 2016-13 is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which a other-than-temporary impairment had been recognized before the effective date. The Company is currently assessing the impact this accounting standard will have on its financial statements and related disclosures.

The Company does not expect the adoption of any other 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. 

5.

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, 2018:

	Oklahoma	Other (1)	Total
Balance May 1, 2018	$3,779,414	$100,000	$3,879,414
Additions	459,634	-	459,634
Depreciation, depletion and amortization	(86,934)	-	(86,934)
Balance July 31, 2018	$4,152,114	$100,000	$4,252,114

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2018, and April 30, 2018, management concluded that impairment was not necessary as all other assets were carried at salvage value.

Kern and Kay County Projects. On February 14, 2018, the Company entered into a Purchase and Exchange Agreement with Red Fork Resources (“Red Fork”), pursuant to which (i) the Company agreed to convey to Mountain View Resources, LLC, an affiliate of Red Fork, 100% of its 13.7% working interest in and to an area of mutual interest (“AMI”) in the Mountain View Project in Kern County, California, and (ii) Red Fork agreed to convey to the Company 64.7% of its 85% working interest in and to an AMI situated in Kay County, Oklahoma (the “Red ForkExchange”). The fair value of the assets acquired was $108,333 as of the effective date of the agreement. Following the Red Fork Exchange, the Company and Red Fork each retained a 2% overriding royalty interest in the projects that they respectively conveyed. Under the terms of the Agreement, all revenues and costs, expenses, obligations and liabilities earned or incurred prior to January 1, 2018 (the “Effective Date”) shall be borne by the original owners of such working interests, and all of such costs, expenses, obligations and liabilities that occur subsequent to the effective date shall be borne by the new owners of such working interests.

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The acquisition of the additional concessions in Kay County, Oklahoma added additional prospect locations adjacent to the Company’s 106,000-acre concession in Osage County, Oklahoma. The similarity of the prospects in Kay and Kern County allows for the leverage of assets, infrastructure and technical expertise.

Oklahoma Properties. During the three months ended July 31, 2018, the Company recorded additions related to development costs incurred of approximately $460,000 for proven oil and gas assets.

6.

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, 2018 and April 30, 2018 based on a future undiscounted liability of $740,452 and $728,091, respectively. These costs are expected to be incurred within 1 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, 2018	Three Months Ended July 31, 2017
Balance, beginning of period	$660,139	$558,696
Additions	4,150	7,500
Change in estimate	(1,088)	-
Disposals	-	-
Accretion	3,423	2,971
	666,624	569,167
Less: Current portion for cash flows expected to be incurred within one year	(406,403)	(406,403)
Long-term portion, end of period	$260,221	$162,764

During the three months ended July 31, 2018 and 2017, the Company recorded accretion expense of $3,423 and $2,971, respectively.

Expected timing of asset retirement obligations:

Year Ending April 30,
2019	$406,403
2020	-
2021	-
2022	-
2023	-
Thereafter	334,049
Subtotal	740,452
Effect of discount	(73,828)
Total	$666,624

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7.

Related Party Transactions

Related Party Loan

On June 18, 2018, Bandolier entered into a loan agreement with Scot Cohen, the Executive Chairman of the Company, pursuant to which Mr. Cohen loaned the Company $300,000 at a 10% annual interest rate, due on September 30, 2018. The Cohen Loan Agreement was to provide the Company with short-term financing in connection with the Company’s drilling program in Osage County, Oklahoma. As of July 31, 2018, the accrued interest was $3,583. 

June 2017 $2.0 Million Secured Note Financing

Scot Cohen owns or controls 31.25% of Funding Corp. I, the holder of the senior secured promissory note in the principal amount of $2.0 million (the “June 2017 Secured Note”) issued by the Company on June 13, 2017. The June 2017 Secured Note accrues interest at a rate of 10% per annum and matures on June 30, 2020. The June 2017 Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

On May 17, 2018, the parties executed an extension of the due date of the first interest payment from June 1, 2018 to December 31, 2018. As consideration for the interest payment extension, the Company agreed to pay Funding Corp. I an additional 10% of the interest due on June 1, 2018 on December 31, 2018. The Company accrued an additional $19,160 of interest expenses related to this extension.

In connection with the issuance of the June 2017 Secured Note, the Company issued to Funding Corp. I warrants to purchase 840,336 shares of the Company’s common stock (the “June 2017 Warrant”). Upon issuance of the June 2017 Secured Note, the Company valued the June 2017 Warrant using the Black-Scholes Option Pricing model and accounted for it using the relative fair value of $952,056 as debt discount on the consolidated balance sheet.

As additional consideration for the purchase of the June 2017 Secured Note, the Company issued to Funding Corp. I 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, originally held by Spyglass, valued at $250,000, which was recorded as contributed capital and 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 $923,364 as of July 31, 2018. During the three months ended July 31, 2018 and 2017, the Company recorded amortization of debt discount totaling $70,824 and $37,378, respectively.

As of July 31, 2018 and April 30, 2018, the outstanding balance, net of debt discount, was $1,076,636 and $1,005,811, respectively, and accrued interest on the June 2017 Secured Note due to related party was $243,636 and $174,065, respectively. 

November 2017 $2.5 Million Secured Note Financing

Scot Cohen owns or controls 41.20% of Funding Corp. II, the holder of the November 2017 Secured Note issued by the Company in connection with the November 2017 Note Financing in the principal amount of $2.5 million. The November 2017 Secured Note accrues interest at a rate of 10% per annum and matures on June 30, 2020. The November 2017 Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

On May 17, 2018, the parties executed an extension of the due date of the first interest payment from June 1, 2018 to December 31, 2018. As consideration for the interest payment extension, the Company agreed to pay Funding Corp. II an additional 10% of the interest due on June 1, 2018 on December 31, 2018. The Company accrued an additional $14,247 of interest expenses related to this extension.

Pursuant to the financing agreement, the Company issued the November 2017 Warrant to Funding Corp. II to purchase 1.25 million shares of the Company’s common stock. Upon issuance of the November 2017 Note, the Company valued the November 2017 Warrant using the Black-Scholes Option Pricing model and accounted for it using the relative fair value of $1,051,171 as debt discount on the consolidated balance sheet. In relation to the financing, Scot Cohen paid $250,000 for an overriding royalty interest from Funding Corp. I (as discussed below), which was recorded as additional debt discount on the consolidated balance sheet.

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As additional consideration for the purchase of the November 2017 Secured Note, the Company issued to Funding Corp. 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, originally held by Spyglass (the “ExistingOsage County Override”) then transferred to Funding Corp. I as inducement for the June 2017 Secured Note. The Existing Osage County Override was then acquired by the Company from Scot Cohen. As noted above, the override was accounted for as a debt discount and amortized over the term of the debt.

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 $1,059,687 as of July 31, 2018. During the three months ended July 31, 2018 and 2017, the Company recorded amortization of debt discount totaling $85,375 and $0, respectively.

As of July 31, 2018 and April 30, 2018, the outstanding balance, net of debt discount, were $1,440,313 and $1,354,938, respectively, and accrued interest on the November 2017 Secured Note due to related party were $197,809 and $120,548, respectively.

8.

Stockholders’ Equity

As of July 31, 2018 and April 30, 2018, the Company had 5,000,000 shares of preferred stock, par value $0.00001 per share, authorized. As of July 31, 2018, and April 30, 2018, 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 has been designated. 

As of July 31, 2018 and April 30, 2018, the Company had 150,000,000 shares of common stock authorized.

In May 2018, the Company granted a total of 260,000 shares of restricted common stock to Scot Cohen and Steven Brunner in exchange for a reduction in cash compensation with a fair value of approximately $325,000, based on the market price of the Company’s common stock on the grant date. The shares vest monthly in equal installments over a 12-month period. During the three months ended July 31, 2018, the Company recorded stock-based compensation of $54,166 related to these grants.

There were 17,569,733 and 17,309,733 shares of common stock issued and outstanding as of July 31, 2018 and April 30, 2018, respectively. 

Stock Options

The assumptions used for the options granted during the three months ended July 31, 2018 were as follows:

	July 31, 2018
Exercise price	$	1.30 – 1.50
Expected dividends		0%
Expected volatility		155.97 – 158.73%
Risk free interest rate		2.08 – 2.96%
Expected life of grants		1 – 10 years

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The following table summarizes information about the changes of options for the period from April 30, 2018 to July 31, 2018, and options outstanding and exercisable at July 31, 2018:

	Options	Weighted Average Exercise Prices
Outstanding April 30, 2018	2,555,385	$2.14
Granted	52,000	1.45
Exercised	-	-
Forfeited/Cancelled	-	-
Outstanding – July 31, 2018	2,607,385	$2.13
Exercisable – July 31, 2018	2,427,588	$2.17
Outstanding – Aggregate Intrinsic Value		$220,485
Exercisable – Aggregate Intrinsic Value		$206,924

The following table summarizes information about the options outstanding and exercisable at July 31, 2018:

	Options Outstanding		Options Exercisable
Exercise Price	Options	Weighted Avg. Life Remaining (years)	Options
$1.30	12,000	0.50	12,000
$1.38	1,795,958	8.09	1,682,947
$1.40	25,703	9.39	25,703
$1.50	40,000	10.00	8,000
$1.98	5,000	8.01	5,000
$2.00	457,402	6.92	431,895
$2.87	65,334	6.55	64,611
$3.00	51,001	7.41	42,445
$3.39	12,000	7.64	12,000
$6.00	10,000	6.49	10,000
$12.00	132,987	5.27	132,987
	2,607,385		2,427,588

During the three months ended July 31, 2018 and 2017, the Company expensed $191,818 and $529,332, 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, 2018, the Company has approximately $199,168 in unrecognized stock-based compensation expense related to unvested options, which will be amortized over a weighted average exercise period of approximately three years.

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Warrants

The fair values of the 840,336 June 2017 Warrants granted in conjunction with the June 2017 Note Financing and the 1.25 million November 2017 Warrants granted in connection with the November 2017 Note Financing (as discussed in Note 7) were estimated on the date of grant using the Black-Scholes option-pricing model.

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

	Number of Warrants	Weighted Average Exercise Price	Weighted Average Life Remaining (Years)
Outstanding and exercisable – April 30, 2018	2,223,669	5.02	2.57
Forfeited	-	-	-
Granted	-	-	-
Outstanding and exercisable – July 31, 2018	2,223,669	5.02	2.08

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

9.

Revenue from Contracts with Customers

Change in Accounting Policy. The Company adopted ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of May 1, 2018. Refer to Note 4 –Significant Accounting Policies for additional information.

Exploration and Production. There were no significant changes to the timing or valuation of revenue recognized for sales of production from exploration and production activities.

Disaggregation of Revenue from Contracts with Customers. The following table disaggregates revenue by significant product type for the three months ended July 31, 2018:

Oil sales	$1,364
Natural gas sales	572,701
Total revenue from customers	$574,065

There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of April 30, 2018 or July 31, 2018.

10.

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.

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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 $582,000 as of July 31, 2018). 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 $510,000 as of July 31, 2018). 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 Company is in the process of negotiating a settlement agreement with the landlord.

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Railroad Commission”) that the Company was not in compliance with regulations promulgated by the Railroad 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 Railroad Commission therefore collected $25,000 from the Company, which was originally deposited with the Railroad Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Railroad 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, the Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals. That appeal is pending as of the filing date of these financial statements. 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.

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. 

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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 (“Common Stock”), 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 on Form 10-Q (the “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 Quarterly 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 Quarterly 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 Quarterly 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 for the year ended April 30, 2018, filed with the SEC on July 30, 2018.

Business Overview

Petro River Oil Corp. is an independent energy company focused on the exploration and development of conventional oil and gas assets with low discovery and development costs, utilizing modern technology. 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 entering 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, including in Osage County and Kay County, Oklahoma. Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company has additional exposure to a portfolio of 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 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. Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

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The Company’s prospects in Oklahoma are owned directly by the Company and indirectly through Spyglass Energy Group, LLC (“Spyglass”), a wholly owned subsidiary of Bandolier Energy, LLC (“Bandolier”). As of January 31, 2018, Bandolier became wholly-owned by the Company. Bandolier has a 75% working interest in the 106,500-acre concession in Osage County, Oklahoma. The remaining 25% working interest is held by the operator, Performance Energy, LLC.

The Company anticipates increasing revenue in subsequent quarters as a result of the Company’s discoveries in Osage County, Oklahoma, and its drilling program for calendar year 2018. Management anticipates deriving increased revenue from existing oil and gas assets and following the completion of its calendar year 2018 drilling program, although no assurances can be given. 

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 continue drilling additional wells on our existing concessions, and to acquire additional 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.

Recent Developments

Recent Oil Discoveries.

On July 24, 2018, the Company announced the discovery of its largest oil field to date with the Company’s successful drilling of the Arsaga 25-2 exploration well, located on its concession in Osage County, Oklahoma. The well was spud on July 9, 2018, and was drilled to a depth of approximately 2,750 feet. Preliminary results indicate 30 feet of productive Mississippian Chat formation. The Arsaga Field spans approximately 2,000 acres, with up to 100 well locations.

On May 22, 2018, the Company announced the discovery of a new oil field, the N. Blackland Field, in its concession in Osage County, Oklahoma, upon successfully testing of the 2-34 exploration well (the “2-34”). The 2-34 was drilled to a depth of approximately 2,850 feet, and initial results indicate both Mississippian Chat and Burges formations were discovered and have been comingled to increase production rates. The N. Blackland Field is approximately 200 acres, and the Company expects to drill an additional eight to ten wells to develop the structure. This structure was identified using 3-D seismic technology. This development project is anticipated to result in production revenue prior to the end of the current fiscal year.

In May 2017, Bandolier discovered two new oil fields with the successful drilling of the W. Blackland 1-3 and S. Blackland 2-11 exploration wells. On December 15, 2017, the Company received permits from the Bureau of Indian Affairs to drill eight additional wells in the W. Blackland Field, which were successfully completed in April 2018. The Company has received additional permits, and is currently in the process of drilling an additional two wells. Our W. Blackland concessions are currently producing, and, with the drilling of additional wells, we anticipate substantially increasing revenue throughout the remainder of the current fiscal year.

In addition to our current development plans, within our current 3-D seismic data, additional structures in Osage County have been identified. The Company plans to drill 13 additional wells in calendar year 2018: nine in the N. Blackland Field, three in the Arsaga structure and one in the Section 13 structure. The Company anticipates drilling these wells out of cash flows from current production of its existing wells.

Cohen Loan Agreement

On June 18, 2018, Bandolier entered into a Loan Agreement with Scot Cohen, the Executive Chairman of the Company (the “Cohen Loan Agreement”), pursuant to which Mr. Cohen loaned the Company $300,000 at a 10% annual interest rate, due on September 30, 2018. The Cohen Loan Agreement was to provide the Company with short-term financing in connection with the Company’s drilling program in Osage County, Oklahoma.  

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Critical Accounting Policies and Estimates

The Company’s significant accounting policies are described in Note 4 to the annual consolidated financial statements for the years ended April 30, 2018 and 2017 on Form 10-K, filed with the SEC on July 30, 2018 for the year ended April 30, 2018.

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. These consolidated financial statements are prepared in accordance with U.S. 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 Quarterly Report 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.

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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% 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.

Revenue Recognition 

ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning May 1, 2018. Refer to Note 9 – Revenue from Contracts with Customers for additional information.

The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

Income Tax Provision

On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. ASC 740, Accounting for Income Taxes, requires companies to recognize the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The Company’s gross deferred tax assets were revalued based on the reduction in the federal statutory tax rate from 35% to 21%. A corresponding offset has been made to the valuation allowance, and any potential other taxes arising due to the Tax Act will result in reductions to the Company’s net operating loss carryforward and valuation allowance. The Company will continue to analyze the Tax Act to assess its full effects on the Company’s financial results, including disclosures, for the Company’s fiscal year ending April 30, 2019, but the Company does not expect the Tax Act to have a material impact on the Company’s consolidated financial statements.

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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.

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).

New Accounting Standards

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases, which aims to make leasing activities more transparent and comparable and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. This ASU is effective for all interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. The Company expects to adopt ASU 2016-02 beginning May 1, 2019and is in the process of assessing the impact that this new guidance is expected to have on the Company’s financial statements and related disclosures.

In September 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. ASU 2016-13 was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. ASU 2016-13 is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which a other-than-temporary impairment had been recognized before the effective date. The Company is currently assessing the impact this accounting standard will have on its financial statements and related disclosures.

The Company does not expect the adoption of any other 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, 2018 Compared to Three Months Ended July 31, 2017

Oil Sales

During the three months ended July 31, 2018, the Company recognized $574,065 in oil and gas sales, compared to $8,803 for the three months ended July 31, 2017. The overall increase in sales of $565,262 is primarily due to the commencement of production in Osage County, Oklahoma.

We have listed below the total production volumes and total revenue net to the Company for the three months ended July 31, 2018 and 2017.

	For the Three Months Ended	For the Three Months Ended
	July 31, 2018	July 31, 2017
Oil volume (BBL)	8,414	100
Gas volume (MCF)	763	2,349
Volume equivalent (BOE)(1)	8,541	492
Revenue	$574,065	$8,803

(1) Assumes 6 Mcf of natural gas is equivalent to 1 barrel of oil.

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Lease Operating Expense

During the three months ended July 31, 2018, lease operating expense was $77,612, compared to $18,362 for the three months ended July 31, 2017. The overall increase in lease operating expense was primarily attributable to increased activity in the Company’s drilling activity in Osage County, Oklahoma.

General and Administrative Expense

General and administrative expense for the three months ended July 31, 2018 was $506,557, compared to $992,557for the three months ended July 31, 2017. 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, 2018	July 31, 2017
Salaries and benefits	$283,484	$578,423
Professional fees	139,620	266,968
Office and administrative	83,453	147,166
Total	$506,557	$992,557

Salaries and benefits include non-cash stock-based compensation of $245,984 for three months ended July 31, 2018, compared to $529,332 for the three months ended July 31, 2017. The decrease in stock-based compensation of $283,348 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.

Interest Income (Expense)

During the three months ended July 31, 2018, the Company recognized $319,580 of net interest expense, compared to interest income of $132,745 for the three months ended July 31, 2017. The interest expense for the three months ended July 31, 2018 included $156,199 and $163,381, which were the accretion of the debt discount and interest expense, respectively, related to the June 2017 $2.0 million and November 2017 $2.5 million Secured Note financings. 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, respectively, related to the June 2017 $2.0 million and November 2017 $2.5 million Secured Note financings.

Liquidity and Capital Resources

At July 31, 2018, the Company had working capital deficit of $1,900,672, of which $4,642 and $211,154 was attributable to ending cash balances and oil and gas accounts receivable, respectively. These amounts are offset by current liabilities of $707,874, $448,996, $259,313, $300,000 and $406,403, which were attributable to accounts payable and accrued expenses, accrued interest on notes payable, outstanding balance pursuant to related party promissory note, the redetermination liability and asset retirement obligations, respectively.

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, 2018, the Company had cash and cash equivalents of approximately $4,642. 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.

On June 18, 2018, the Company entered into the Cohen Loan Agreement with Scot Cohen, pursuant to which Mr. Cohen loaned the Company $300,000 at a 10% annual interest rate due September 30, 2018.

The current level of working capital may be insufficient to maintain current operations as well as the planned added operations for the next 12 months. Management intends to raise capital through debt and equity instruments, if necessary, in order to execute its business and operating plans. Management can provide no assurances that the Company will be successful in any capital raising efforts. In order to conserve capital, from time to time, management may defer certain development activity.

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Operating Activities

During the three months ended July 31, 2018, operating activities provided cash of $29,864, compared to $65,678 used in operating activities during the three months ended July 31, 2017. The Company incurred a net loss during the three months ended July 31, 2018 of $420,231, compared to a net loss of $805,205 for the three months ended July 31, 2017. For the three months ended July 31, 2018, the net loss was offset by non-cash items such as stock-based compensation, depreciation, depletion and accretion of asset retirement obligation and accretion of debt discount. Cash used in operations was also influenced by changes in accounts receivable, accrued interest on notes receivable, prepaid expense and accounts payable and accrued expense. 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 used in operations was also influenced by changes in accounts receivable, accrued interest on notes receivable, prepaid expenses and accounts payable and accrued expenses.

Investing Activities

Investing activities during the three months ended July 31, 2018, resulted in cash used of $372,552, compared to cash used of $1,398,430 during the three months ended July 31, 2017. During the three months ended July 31, 2018, the Company invested an additional $0 in Horizon Energy, compared to $379,418 in the comparable period in 2017. During the three months ended July 31, 2017, the Company received proceeds of $1,557,852 from profits in its real estate rights. As a result of the Assignment and Assumption of Membership Interest entered into by and between the Company and MegaWest Energy Kansas Corp. on January 31, 2018, the Company no longer has any interest in real estate rights, and this did not receive any profits in real estate rights for the three months ended July 31, 2018. During the three months ended July 31, 2018, the Company incurred $372,552 of expenditures on oil and gas assets, compared to $736,964 for the three months ended July 31, 2017. During the three months ended July 31, 2018, the Company executed notes receivable agreements with related parties resulting in the outlay of $0, compared to $1,558,501 during the corresponding period ended July 31, 2017.

Financing Activities

Financing activities during the three months ended July 31, 2018, resulted in cash provided of $300,000, compared to $2,000,000during the three months ended July 31, 2017.

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, 2018	July 31, 2017
Common shares	17,569,733	15,840,143
Stock options	2,607,385	2,574,682
Stock purchase warrants	2,223,669	973,669
	22,400,787	19,388,494

Off-Balance Sheet Arrangements

None.

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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, 2018, 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, as amended, 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 U.S. 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.

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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 $582,000 as of July 31, 2018). 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 $510,000 as of July 31, 2018). 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 Company is in the process of negotiating a settlement agreement with the landlord.

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Railroad Commission”) that the Company was not in compliance with regulations promulgated by the Railroad 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 Railroad Commission therefore collected $25,000 from the Company, which was originally deposited with the Railroad Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Railroad 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, the Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals. That appeal is pending as of the filing date of these financial statements. 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.

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, 2018, filed on July 30, 2018. 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 September 14, 2018, there have been no material changes to the disclosures made in the above-referenced Form 10-K.

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, 2018.

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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.

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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, 2018

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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, 2018

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, 2018

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, 2018, 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, 2018

/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, 2018, 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, 2018

/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.

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Document and Entity Information - shares	3 Months Ended
	Jul. 31, 2018	Sep. 14, 2018
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, 2018
Amendment Flag	false
Current Fiscal Year End Date	--04-30
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		17,569,809
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2019

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Consolidated Balance Sheets (Unaudited) - USD ($)	Jul. 31, 2018	Apr. 30, 2018
Current Assets:
Cash and cash equivalents	$ 4,642	$ 47,330
Accounts receivable - oil and gas	211,154	308,099
Prepaid expenses and other current assets	6,118	612
Total Current Assets	221,914	356,041
Oil and gas assets, full cost method
Costs subject to amortization, net	4,152,114	3,779,414
Costs not being amortized, net	100,000	100,000
Property, plant and equipment, net	632	822
Investment in Horizon Energy Partners, LLC	1,592,418	1,592,418
Other assets	17,133	17,133
Total Long-term Assets	5,862,297	5,489,787
Total Assets	6,084,211	5,845,828
Current Liabilities:
Accounts payable and accrued expenses	707,874	908,343
Accrued interest on notes payable – related party	448,996	298,581
Promissory note payable - related party	300,000	0
Redetermination liability	259,313	259,313
Asset retirement obligations, current portion	406,403	413,794
Total Current Liabilities	2,122,586	1,880,031
Long-term liabilities:
Asset retirement obligations, net of current portion	260,221	246,345
Notes payable - related parties, net of debt discount of $1,983,051 and $2,139,250, respectively	2,516,949	2,360,750
Total Long-term Liabilities	2,777,170	2,607,095
Total Liabilities	4,899,756	4,487,126
Commitments and contingencies
Equity:
Preferred shares	0	0
Common shares - 150,000,000 authorized; par value $0.00001; 17,569,733 and 17,309,733 issued and outstanding, respectively	176	173
Additional paid-in capital	52,653,524	52,407,543
Accumulated deficit	(51,469,245)	(51,049,014)
Total Equity	1,184,455	1,358,702
Total Liabilities and Equity	6,084,211	5,845,828
Preferred B Shares [Member]
Equity:
Preferred shares	$ 0	$ 0

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Consolidated Balance Sheets (Parenthetical) - USD ($)	Jul. 31, 2018	Apr. 30, 2018
Note payable debt discount	$ 1,983,051	$ 2,139,250
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	150,000,000	150,000,000
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares issued	17,569,733	17,309,733
Common stock, shares outstanding	17,569,733	17,309,733
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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Consolidated Statements of Operations - USD ($)	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017
Revenues
Oil and natural gas sales	$ 574,065	$ 8,803
Total Revenues	574,065	8,803
Operating Expenses
Lease operating expenses	77,612	18,362
Depreciation, depletion and accretion	90,547	9,120
General and administrative	506,557	992,557
Total Operating Expenses	674,716	1,020,039
Operating Loss	(100,651)	(1,011,236)
Total Other Income (Expense)
Interest income (expense) - net	(319,580)	132,745
Net gain on real estate rights	0	271,490
Other Income (Expense)	(319,580)	404,235
Net Loss Before Income Tax Provision	(420,231)	(607,001)
Income Tax Provision	0	198,204
Net Loss	(420,231)	(805,205)
Net Income Attributable to Non-controlling Interest	0	74,571
Net Loss Attributable to Petro River Oil Corp. and Subsidiaries	$ (420,231)	$ (879,776)
Loss Per Common Share - Basic and Diluted	$ (.02)	$ (0.06)
Weighted average number of common shares outstanding - Basic and diluted	17,504,019	15,835,095

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Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (420,231)	$ (805,205)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	245,984	529,332
Depreciation, depletion and accretion	90,547	9,120
Amortization of debt discount	156,199	37,378
Net gain on interest in real estate rights	0	(271,490)
Deferred income tax expense	0	198,204
Changes in operating assets and liabilities:
Accounts receivable - oil and gas	96,945	(246)
Accrued interest on notes receivable- related party	0	(194,599)
Prepaid expenses and other current assets	(5,506)	175,464
Accrued interest on notes payable – related party	150,415	0
Accounts payable and accrued expenses	(284,490)	256,364
Net Cash Provided by (Used in) Operating Activities	29,863	(65,678)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of interest in real estate rights	0	1,557,852
Prepaid oil and gas assets	0	(281,399)
Issuance of notes receivable - related party	0	(1,558,501)
Capitalized expenditures on oil and gas assets	(372,551)	(736,964)
Cash paid for cost method investment	0	(379,418)
Net Cash Used in Investing Activities	(372,551)	(1,398,430)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable - related party	300,000	2,000,000
Net Cash Provided by Financing Activities	300,000	2,000,000
Change in cash and cash equivalents	(42,688)	535,892
Cash and cash equivalents, beginning of period	47,330	631,232
Cash and cash equivalents, end of period	4,642	1,167,124
Cash paid during the period for:
Income taxes	0	34,052
Interest paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Additions to asset retirement obligation from new drilling	3,062	7,500
Warrants issued with notes payable	$ 0	$ 952,056

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Organization

3 Months Ended

Jul. 31, 2018

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, utilizing modern technology. 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 entering 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, including in Osage County and Kay County, Oklahoma. Following the acquisition of Horizon I Investments, LLC (“Horizon Investments”), the Company has additional exposure to a portfolio of 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 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. Each of the assets in the Horizon Energy portfolio is characterized by low initial capital expenditure requirements and strong risk reward characteristics.

The Company’s prospects in Oklahoma are owned directly by the Company and indirectly through Spyglass Energy Group, LLC (“Spyglass”), a wholly owned subsidiary of Bandolier Energy, LLC (“Bandolier”). As of January 31, 2018, Bandolier became wholly-owned by the Company. Bandolier has a 75% working interest in the 87,754-acre concession in Osage County, Oklahoma. The remaining 25% working interest is held by the operator, Performance Energy, LLC.

The execution of the Company’s 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, the Company plans to continue drilling additional wells on its existing concessions, and to acquire additional high-quality oil and gas properties, primarily proved producing, and proved undeveloped reserves. The Company also intends to explore low-risk development drilling and work-over opportunities. Management is also exploring farm-in and joint venture opportunities for the Company’s oil and gas assets.

Recent Developments

Recent Oil Discoveries.

On July 24, 2018, the Company announced the successful drilling of the Arsaga 25-2 exploration well, located on its concession in Osage County, Oklahoma.

On May 22, 2018, the Company announced the discovery of a new oil field, the N. Blackland Field, in its concession in Osage County, Oklahoma, upon successfully testing of the 2-34 exploration well.

In May 2017, Bandolier discovered two new oil fields with the successful drilling of the W. Blackland 1-3 and S. Blackland 2-11 exploration wells. On December 15, 2017, the Company received permits from the Bureau of Indian Affairs to drill eight additional wells in the W. Blackland Field, which were successfully completed in April 2018. The Company has received additional permits, and is currently in the process of drilling an additional two wells. The Company’s W. Blackland concessions are currently producing, and, with the drilling of additional wells, the Company anticipates substantially increasing revenue throughout the remainder of the current fiscal year.

In addition to the Company’s current development plans, within its current 3-D seismic data, additional structures in Osage County have been identified. The Company plans to drill 13 additional wells in calendar year 2018: nine in the N. Blackland Field, three in the Arsaga structure and one in the Section 13 structure. The Company anticipates drilling these wells out of cash flows from current production of its existing wells.

Cohen Loan Agreement

On June 18, 2018, Bandolier entered into a loan agreement with Scot Cohen, the Executive Chairman of the Company (the “Cohen Loan Agreement”), pursuant to which Scot Cohen loaned the Company $300,000 at a 10% annual interest rate, due on September 30, 2018. The Cohen Loan Agreement was to provide the Company with short-term financing in connection with the Company’s drilling program in Osage County, Oklahoma.  

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Going Concern and Management’s Plan

3 Months Ended

Jul. 31, 2018

Going Concern And Managements Plan

Going Concern and Management's Plan

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As of July 31, 2018, the Company had an accumulated deficit of $51.5 million. The Company has incurred significant losses since its inception. These matters raise substantial doubt about the Company’s ability to continue as a going concern for the twelve months following the issuance of these financial statements. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset amounts or the classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

At July 31, 2018, the Company had working deficit of approximately $1.9 million . 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 prior to its acquisition of Bandolier. At July 31, 2018, the Company had cash and cash equivalents of approximately $5,000. The Company’s primary source of operating funds since inception has been debt and equity financings.

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. In addition, 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.

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Basis of Preparation

3 Months Ended

Jul. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Preparation

The accompanying unaudited interim consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States (“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.

As a result of the Acquisition of Membership Interest in the Osage County Concession in November 2017, Bandolier is now a wholly-owned subsidiary of the Company and the Company consolidates 100% of the financial information of Bandolier. Bandolier operates the Company’s Oklahoma oil and gas properties.

Also contained in the unaudited consolidated financial statements for the periods ending July 31, 2017 and April 30, 2018 is the financial information of MegaWest, which, prior to January 31, 2018, was 58.51% owned by the Company. The unaudited consolidated financial statements for the three months ended July 31, 2017 include the results of operations of MegaWest; however, the assets and liabilities were written off in the year ended April 30, 2018.

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, 2018, filed with the Securities and Exchange Commission (the “SEC”) on July 30, 2018. 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, 2018, 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, 2019.

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Significant Accounting Policies

3 Months Ended

Jul. 31, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

 (a) Use of Estimates:

The preparation of financial statements in conformity with U.S. GAAP 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 management believe that its 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. 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, 2018 and April 30, 2018 was $0.

 (d) 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.

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 Company’s acquisition of its interest in Bandolier. The price used to establish economic viability 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.

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, 2018 and 2017.  

 (e) 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.

 (f) Revenue Recognition:

ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning May 1, 2018. Refer to Note 9 – Revenue from Contracts with Customers for additional information.

The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

 (g) 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 the Company’s 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.

 (h) Income Taxes:

Income Tax Provision

On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. ASC 740, Accounting for Income Taxes, requires companies to recognize the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The Company’s gross deferred tax assets were revalued based on the reduction in the federal statutory tax rate from 35% to 21%. A corresponding offset has been made to the valuation allowance, and any potential other taxes arising due to the Tax Act will result in reductions to the Company’s net operating loss carryforward and valuation allowance. The Company will continue to analyze the Tax Act to assess its full effects on the Company’s financial results, including disclosures, for the Company’s fiscal year ending April 30, 2019, but the Company does not expect the Tax Act to have a material impact on the Company’s consolidated financial statements.

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.

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).

 (i) Per Share Amounts:

Basic net income (loss) per common share is computed by dividing net loss attributable to stockholders by the weighted-average number of shares of common stock 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, 2018 and 2017, 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, 2018 and 2017:

	July 31, 2018		July 31, 2017
Stock Options		2,607,385		2,574,682
Stock Purchase Warrants		2,223,669		973,669
Total		4,831,054		3,548,351

  (j) Recent Accounting Pronouncements:

In February 2016, the FASB issued ASU 2016-02, Leases, which aims to make leasing activities more transparent and comparable and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. This ASU is effective for all interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. The Company expects to adopt ASU 2016-02 beginning May  1, 2019 and is in the process of assessing the impact that this new guidance is expected to have on the Company’s financial statements and related disclosures.

In September 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. ASU 2016-13 was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. ASU 2016-13 is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which a other-than-temporary impairment had been recognized before the effective date. The Company is currently assessing the impact this accounting standard will have on its financial statements and related disclosures.

The Company   does not expect the adoption of any other 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. 

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Oil and Gas Assets

3 Months Ended

Jul. 31, 2018

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, 2018:

	Oklahoma			Other (1)		Total
Balance May 1, 2018	$	3,779,414		$	100,000	$	3,879,414
Additions		459,634			-		459,634
Depreciation, depletion and amortization		(86,934	)		-		(86,934	)
Balance July 31, 2018	$	4,152,114		$	100,000	$	4,252,114

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2018, and April 30, 2018, management concluded that impairment was not necessary as all other assets were carried at salvage value.

Kern and Kay County Projects.  On February 14, 2018, the Company entered into a Purchase and Exchange Agreement with Red Fork Resources (“Red Fork”), pursuant to which (i) the Company agreed to convey to Mountain View Resources, LLC, an affiliate of Red Fork, 100% of its 13.7% working interest in and to an area of mutual interest (“AMI”) in the Mountain View Project in Kern County, California, and (ii) Red Fork agreed to convey to the Company 64.7% of its 85% working interest in and to an AMI situated in Kay County, Oklahoma (the “Red Fork Exchange”). The fair value of the assets acquired was $108,333 as of the effective date of the agreement. Following the Red Fork Exchange, the Company and Red Fork each retained a 2% overriding royalty interest in the projects that they respectively conveyed. Under the terms of the Agreement, all revenues and costs, expenses, obligations and liabilities earned or incurred prior to January 1, 2018 (the “Effective Date”) shall be borne by the original owners of such working interests, and all of such costs, expenses, obligations and liabilities that occur subsequent to the effective date shall be borne by the new owners of such working interests.

The acquisition of the additional concessions in Kay County, Oklahoma added additional prospect locations adjacent to the Company’s 106,000-acre concession in Osage County, Oklahoma. The similarity of the prospects in Kay and Kern County allows for the leverage of assets, infrastructure and technical expertise.

Oklahoma Properties. During the three months ended July 31, 2018, the Company recorded additions related to development costs incurred of approximately $460,000 for proven oil and gas assets.

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Asset Retirement Obligations

3 Months Ended

Jul. 31, 2018

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, 2018 and April 30, 2018 based on a future undiscounted liability of $740,452 and $728,091, respectively. These costs are expected to be incurred within 1 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, 2018			Three Months Ended July 31, 2017
Balance, beginning of period	$	660,139		$	558,696
Additions		4,150			7,500
Disposals		-			-
Accretion		2,335			2,971
		666,624			569,167
Less: Current portion for cash flows expected to be incurred within one year		(406,403	)		(406,403	)
Long-term portion, end of period	$	260,221		$	162,764

During the three months ended July 31, 2018 and 2017, the Company recorded accretion expense of $2,335 and $2,971, respectively.

Expected timing of asset retirement obligations:

Year Ending April 30,
2019	$	406,403
2020		-
2021		-
2022		-
2023		-
Thereafter		334,049
Subtotal		740,452
Effect of discount		(73,828	)
Total	$	666,624

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Related Party Transactions

3 Months Ended

Jul. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Loan

On June 18, 2018, Bandolier entered into a loan agreement with Mr. Cohen, the Executive Chairman of the Company, pursuant to which Scot Cohen loaned the Company $300,000 at a 10% annual interest rate, due on September 30, 2018. The Cohen Loan Agreement was to provide the Company with short-term financing in connection with the Company’s drilling program in Osage County, Oklahoma. As of July 31, 2018, the accrued interest was $3,583. 

June 2017 $2.0 Million Secured Note Financing

Scot Cohen owns or controls 31.25% of Funding Corp. I, the holder of the senior secured promissory note in the principal amount of $2.0 million (the “June 2017 Secured Note”) issued by the Company on June 13, 2017. The June 2017 Secured Note accrues interest at a rate of 10% per annum and matures on June 30, 2020. The June 2017 Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

On May 17, 2018, the Company executed an extension of the due date of the first payment from June 1, 2018 to December 31, 2018. As consideration for the interest payment extension, the Company agreed to pay Funding Corp. I an additional 10% of the interest due on June 1, 2018 on December 31, 2018. The Company accrued an additional $19,160 of interest expenses related to this extension.

In connection with the issuance of the June 2017 Secured Note, the Company issued to Funding Corp. I warrants to purchase 840,336 shares of the Company’s common stock (the “June 2017 Warrant”). Upon issuance of the June 2017 Secured Note, the Company valued the June 2017 Warrant using the Black-Scholes Option Pricing model and accounted for it using the relative fair value of $952,056 as debt discount on the consolidated balance sheet.

As additional consideration for the purchase of the June 2017 Secured Note, the Company issued to Funding Corp. I 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, originally held by Spyglass, valued at $250,000, which was recorded as contributed capital and 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 $923,364 as of July 31, 2018. During the three months ended July 31, 2018 and 2017, the Company recorded amortization of debt discount totaling $70,824 and $37,378, respectively.

As of July 31, 2018 and April 30, 2018, the outstanding balance, net of debt discount, was $1,076,636 and $1,005,811, respectively, and accrued interest on the June 2017 Secured Note due to related party was $243,636 and $174,065, respectively. 

November 2017 $2.5 Million Secured Note Financing

Scot Cohen owns or controls 41.20% of Funding Corp. II, the holder of the November 2017 Secured Note issued by the Company in connection with the November 2017 Note Financing in the principal amount of $2.5 million. The November 2017 Secured Note accrues interest at a rate of 10% per annum and matures on June 30, 2020. The November 2017 Secured Note is presented as “Note payable – related party, net of debt discount” on the consolidated balance sheets.

On May 17, 2018, the Company executed an extension of the due date of the first payment from June 1, 2018 to December 31, 2018. As consideration for the interest payment extension, the Company agreed to pay Funding Corp. II an additional 10% of the interest due on June 1, 2018 on December 31, 2018. The Company accrued an additional $14,247 of interest expenses related to this extension.

Pursuant to the financing agreement, the Company issued the November 2017 Warrant to Funding Corp. II to purchase 1.25 million shares of the Company’s Common Stock. Upon issuance of the November 2017 Note, the Company valued the November 2017 Warrant using the Black-Scholes Option Pricing model and accounted for it using the relative fair value of $1,051,171 as debt discount on the consolidated balance sheet. In relation to the financing, Scot Cohen paid $250,000 for an overriding royalty interest from Funding Corp. I (as discussed below), which was recorded as additional debt discount on the consolidated balance sheet.

As additional consideration for the purchase of the November 2017 Secured Note, the Company issued to Funding Corp. 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, originally held by Spyglass (the “Existing Osage County Override”) then transferred to Funding Corp. I as inducement for the June 2017 Secured Note. The Existing Osage County Override was then acquired by the Company from Scot Cohen. As noted above, the override was accounted for as a debt discount and amortized over the term of the debt.

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 $1,059,687 as of July 31, 2018. During the three months ended July 31, 2018 and 2017, the Company recorded amortization of debt discount totaling $85,375 and $0, respectively.

As of July 31, 2018 and April 30, 2018, the outstanding balance, net of debt discount, were $1,440,313 and $1,354,938, respectively, and accrued interest on the November 2017 Secured Note due to related party were $197,809 and $120,548, respectively.

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Stockholders' Equity

3 Months Ended

Jul. 31, 2018

Stockholders' Equity Note [Abstract]

Stockholders' Equity

As of July 31, 2018 and April 30, 2018, the Company had 5,000,000 shares of preferred stock, par value $0.00001 per share, authorized. As of July 31, 2018, and April 30, 2018, 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 has been designated. 

As of July 31, 2018 and April 30, 2018, the Company had 150,000,000 shares of Common Stock authorized.

In May 2018, the Company granted a total of 260,000 shares of restricted common stock to Scot Cohen and Steven Brunner in exchange for a reduction in cash compensation with a fair value of approximately $325,000, based on the market price of the Company’s common stock on the grant date. The shares vest monthly in equal installments over a 12-month period. During the three months ended July 31, 2018, the Company recorded stock-based compensation of $54,166 related to these grants

There were 17,569,733 and 17,309,733 shares of common stock issued and outstanding as of July 31, 2018 and April 30, 2018, respectively. 

Stock Options

The assumptions used for the options granted during the three months ended July 31, 2018 were as follows:

	July 31, 2018
Exercise price	$	1.30 – 1.50
Expected dividends		0%
Expected volatility		155.97 – 158.73%
Risk free interest rate		2.08 – 2.96%
Expected life of grants		1-10 years

The following table summarizes information about the changes of options for the period from April 30, 2018 to July 31, 2018 and options outstanding and exercisable at July 31, 2018:

	Options		Weighted Average Exercise Prices
Outstanding April 30, 2018		2,555,385	$	2.14
Granted		52,000		1.45
Exercised		-		-
Forfeited/Cancelled		-		-
Outstanding – July 31, 2018		2,607,385	$	2.13
Exercisable – July 31, 2018		2,429,492	$	2.18
Outstanding – Aggregate Intrinsic Value			$	220,485
Exercisable – Aggregate Intrinsic Value			$	205,055

The following table summarizes information about the options outstanding and exercisable at July 31, 2018:

		Options Outstanding				Options Exercisable
Exercise Price		Options		Weighted Avg. Life Remaining (years)		Options
$	1.30		12,000		0.50		12,000
$	1.38		1,795,958		8.09		1,682,946
$	1.40		25,703		9.39		25,703
$	1.50		40,000		10.00		8,000
$	1.98		5,000		8.01		5,000
$	2.00		457,402		6.92		431,895
$	2.87		65,334		6.55		64,611
$	3.00		51,001		7.41		42,445
$	3.39		12,000		7.64		12,000
$	6.00		10,000		6.49		10,000
$	12.00		132,987		5.27		132,987
			2,607,385				2,427,587

During the three months ended July 31, 2018 and 2017, the Company expensed $191,818 and $529,332, 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, 2018, the Company has approximately $199,168 in unrecognized stock-based compensation expense related to unvested options, which will be amortized over a weighted average exercise period of approximately three years.

Warrants

The fair values of the 840,336 June 2017 Warrants granted in conjunction with the June 2017 Note Financing and the 1.25 million November 2017 Warrants granted in connection with the November 2017 Note Financing (as discussed in Note 7) were estimated on the date of grant using the Black-Scholes option-pricing model. 

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

	Number of Warrants		Weighted Average Exercise Price		Weighted Average Life Remaining (Years)
Outstanding and exercisable – April 30, 2018		2,223,669		5.02		2.57
Forfeited		-		-		-
Granted		-		-		-
Outstanding and exercisable – July 31, 2018		2,223,669		5.02		2.08

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

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Revenue from Contracts with Customers

3 Months Ended

Jul. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

Change in Accounting Policy. The Company adopted ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of May 1, 2018. Refer to Note 4 – Summary of Significant Accounting Policies for additional information.

Exploration and Production. There were no significant changes to the timing or valuation of revenue recognized for sales of production from exploration and production activities.

Disaggregation of Revenue from Contracts with Customers. The following table disaggregates revenue by significant product type for the three months ended July 31, 2018:

Oil sales	$ 1,364
Natural gas sales	572,701
Total revenue from customers	$ 574,065

There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of April 30, 2018 or July 31, 2018.

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Contingency and Contractual Obligations

3 Months Ended

Jul. 31, 2018

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 $582,000 as of July 31, 2018). 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 $510,000 as of July 31, 2018). 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 Company is in the process of negotiating a settlement agreement with the landlord.

(b) In September 2013, the Company was notified by the Railroad Commission of Texas (the “Railroad Commission”) that the Company was not in compliance with regulations promulgated by the Railroad 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 Railroad Commission therefore collected $25,000 from the Company, which was originally deposited with the Railroad Commission, to cover a portion of the estimated costs of $88,960 to plug the wells. In addition to the above, the Railroad 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, the Plaintiffs filed a Notice of Appeal to the Tenth Circuit Court of Appeals. That appeal is pending as of the filing date of these financial statements. 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.

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. 

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Significant Accounting Policies (Policies)

3 Months Ended

Jul. 31, 2018

Accounting Policies [Abstract]

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP 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 management believe that its 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. 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, 2018 and April 30, 2018 was $0.

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.

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 Company’s acquisition of its interest in Bandolier. The price used to establish economic viability 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.

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, 2018 and 2017.  

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.

Revenue Recognition

ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”, supersedes the revenue recognition requirements and industry-specific guidance under Revenue Recognition (Topic 605). Topic 606 requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted Topic 606 on May 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as a result of this adoption. While the Company does not expect 2018 net earnings to be materially impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning May 1, 2018. Refer to Note 9 – Revenue from Contracts with Customers for additional information.

The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues.

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 the Company’s 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

On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. ASC 740, Accounting for Income Taxes, requires companies to recognize the effects of changes in tax laws and rates on deferred tax assets and liabilities and the retroactive effects of changes in tax laws in the period in which the new legislation is enacted. The Company’s gross deferred tax assets were revalued based on the reduction in the federal statutory tax rate from 35% to 21%. A corresponding offset has been made to the valuation allowance, and any potential other taxes arising due to the Tax Act will result in reductions to the Company’s net operating loss carryforward and valuation allowance. The Company will continue to analyze the Tax Act to assess its full effects on the Company’s financial results, including disclosures, for the Company’s fiscal year ending April 30, 2019, but the Company does not expect the Tax Act to have a material impact on the Company’s consolidated financial statements.

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.

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 stockholders by the weighted-average number of shares of common stock 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, 2018 and 2017, 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, 2018 and 2017:

	July 31, 2018		July 31, 2017
Stock Options		2,607,385		2,574,682
Stock Purchase Warrants		2,223,669		973,669
Total		4,831,054		3,548,351

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases, which aims to make leasing activities more transparent and comparable and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. This ASU is effective for all interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. The Company expects to adopt ASU 2016-02 beginning May  1, 2019 and is in the process of assessing the impact that this new guidance is expected to have on the Company’s financial statements and related disclosures.

In September 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses. ASU 2016-13 was issued to provide more decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology. ASU 2016-13 is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method. A prospective transition approach is required for debt securities for which a other-than-temporary impairment had been recognized before the effective date. The Company is currently assessing the impact this accounting standard will have on its financial statements and related disclosures.

The Company   does not expect the adoption of any other 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, 2018

Accounting Policies [Abstract]

Schedule of Common Stock Equivalents

	July 31, 2018		July 31, 2017
Stock Options		2,607,385		2,574,682
Stock Purchase Warrants		2,223,669		973,669
Total		4,831,054		3,548,351

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Oil and Gas Assets (Tables)

3 Months Ended

Jul. 31, 2018

Extractive Industries [Abstract]

Schedule of Oil and Gas Assets

	Oklahoma			Other (1)		Total
Balance May 1, 2018	$	3,779,414		$	100,000	$	3,879,414
Additions		459,634			-		459,634
Depreciation, depletion and amortization		(86,934	)		-		(86,934	)
Balance July 31, 2018	$	4,152,114		$	100,000	$	4,252,114

(1) Other property consists primarily of four used steam generators and related equipment that will be assigned to future projects. As of July 31, 2018, and April 30, 2018, 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, 2018

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes to Asset Retirement Obligation

	Three Months Ended July 31, 2018			Three Months Ended July 31, 2017
Balance, beginning of period	$	660,139		$	558,696
Additions		4,150			7,500
Disposals		-			-
Accretion		2,335			2,971
		666,624			569,167
Less: Current portion for cash flows expected to be incurred within one year		(406,403	)		(406,403	)
Long-term portion, end of period	$	260,221		$	162,764

Schedule of Expected Timing of Asset Retirement Obligations

Year Ending April 30,
2019	$	406,403
2020		-
2021		-
2022		-
2023		-
Thereafter		334,049
Subtotal		740,452
Effect of discount		(73,828	)
Total	$	666,624

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Stockholders' Equity (Tables)

3 Months Ended

Jul. 31, 2018

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

Schedule of options assumptions

	July 31, 2018
Exercise price $		1.30 – 1.50
Expected dividends		0%
Expected volatility		155.97 – 158.73%
Risk free interest rate		2.08 – 2.96%
Expected life of grants		1-10 years

Schedule of Changes in Stock Options

	Options		Weighted Average Exercise Prices
Outstanding April 30, 2018		2,555,385	$	2.14
Granted		52,000		1.45
Exercised		-		-
Forfeited/Cancelled		-		-
Outstanding – July 31, 2018		2,607,385	$	2.13
Exercisable – July 31, 2018		2,429,492	$	2.18
Outstanding – Aggregate Intrinsic Value			$	220,485
Exercisable – Aggregate Intrinsic Value			$	205,055

Summary of Options Outstanding and Exercisable

		Options Outstanding				Options Exercisable
Exercise Price		Options		Weighted Avg. Life Remaining (years)		Options
$	1.30		12,000		0.50		12,000
$	1.38		1,795,958		8.09		1,682,946
$	1.40		25,703		9.39		25,703
$	1.50		40,000		10.00		8,000
$	1.98		5,000		8.01		5,000
$	2.00		457,402		6.92		431,895
$	2.87		65,334		6.55		64,611
$	3.00		51,001		7.41		42,445
$	3.39		12,000		7.64		12,000
$	6.00		10,000		6.49		10,000
$	12.00		132,987		5.27		132,987
			2,607,385				2,427,587

Summary of Warrants Outstanding and Exercisable

	Number of Warrants		Weighted Average Exercise Price		Weighted Average Life Remaining (Years)
Outstanding and exercisable – April 30, 2018		2,223,669		5.02		2.57
Forfeited		-		-		-
Granted		-		-		-
Outstanding and exercisable – July 31, 2018		2,223,669		5.02		2.08

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Revenue from Contracts with Customers (Tables)

3 Months Ended

Jul. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of revenue

Oil sales	$ 1,364
Natural gas sales	572,701
Total revenue from customers	$ 574,065

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Organization (Details Narrative)	Jul. 31, 2018
Horizon Energy [Member]
Equity ownership	20.00%
MegaWest [Member]
Equity ownership	58.51%
Bandolier [Member]
Equity ownership	100.00%

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Going Concern and Management’s Plan (Details Narrative) - USD ($)	Jul. 31, 2018	Apr. 30, 2018	Jul. 31, 2017	Apr. 30, 2017
Going Concern And Managements Plan Details Narrative
Accumulated deficit	$ (51,469,245)	$ (51,049,014)
Cash and cash equivalents	$ 4,642	$ 47,330	$ 1,167,124	$ 631,232

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Basis of Preparation (Details Narrative)	Jul. 31, 2018
Horizon Energy [Member]
Equity ownership	20.00%
MegaWest [Member]
Equity ownership	58.51%
Bandolier [Member]
Equity ownership	100.00%

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Significant Accounting Policies (Details) - shares	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017
Common stock equivalent shares	4,831,054	3,548,351
Stock Options [Member]
Common stock equivalent shares	2,607,385	2,574,682
Stock Purchase Warrants [Member]
Common stock equivalent shares	2,223,669	973,669

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Significant Accounting Policies (Details Narrative) - USD ($)	Jul. 31, 2018	Apr. 30, 2018
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 0	$ 0

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Oil and Gas Assets (Details)	3 Months Ended
	Jul. 31, 2018 USD ($)
Oil and gas assets, net	$ 3,879,414
Additions	459,634
Depreciation, depletion and amortization	(86,934)
Oil and gas assets, net	4,252,114
Oklahoma [Member]
Oil and gas assets, net	3,779,414
Additions	459,634
Depreciation, depletion and amortization	(86,934)
Oil and gas assets, net	4,152,114
Other [Member]
Oil and gas assets, net	100,000	[1]
Additions	0	[1]
Depreciation, depletion and amortization	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, 2018, and April 30, 2018, 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, 2018	Jul. 31, 2017	Apr. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Balance, beginning of period	$ 660,139	$ 558,696
Additions	4,150	7,500
Disposals	0	0
Accretion	2,335	2,971
Total asset retirement obligations	666,624	569,167
Less: Current portion for cash flows expected to be incurred within one year	(406,403)	(406,403)	$ (413,794)
Long-term portion, end of period	$ 260,221	$ 162,764

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Asset Retirement Obligations (Details 1) - USD ($)	Jul. 31, 2018	Apr. 30, 2018	Jul. 31, 2017	Apr. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
2019 (remainder of year)	$ 406,403
2020	0
2021	0
2022	0
2023	0
Thereafter	334,049
Subtotal	740,452	$ 728,091
Effect of discount	(73,828)
Total	$ 666,624	$ 660,139	$ 569,167	$ 558,696

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Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017	Apr. 30, 2018
Asset Retirement Obligation, future liability	$ 740,452		$ 728,091
Accretion expense	$ 2,335	$ 2,971
Minimum
Costs are expected to be incurred, minimum period	1 year
Maximum
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, 2018	Jul. 31, 2017
Amortization of debt discount	$ 156,199	$ 37,378
June 2017 $2.0 Million Secured Note Financing
Unamortized debt discount	923,364
Amortization of debt discount	70,824	37,378
November 2017 $2.5 Million Secured Note Financing
Unamortized debt discount	1,059,687
Amortization of debt discount	$ 85,375	$ 0

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Stockholders' Equity (Details)	3 Months Ended
	Jul. 31, 2018 $ / shares
Expected dividends	0.00%
Minimum
Exercise price	$ 1.30
Expected volatility	155.97%
Risk free interest rate	2.08%
Expected life of warrant	1 year
Maximum
Exercise price	$ 1.50
Expected volatility	158.73%
Risk free interest rate	2.96%
Expected life of warrant	10 years

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Stockholders' Equity (Details 1)	3 Months Ended
	Jul. 31, 2018 USD ($) $ / shares shares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options, Outstanding, beginning balance | shares	2,555,385
Number of Options, Granted | shares	52,000
Number of Options, Exercised | shares	0
Number of Options, Forfeited/Cancelled | shares	0
Number of Options, Outstanding, ending balance | shares	2,607,385
Number of Options, Exercisable | shares	2,429,492
Weighted Avg. Exercise Price, Outstanding | $ / shares	$ 2.14
Weighted Avg. Exercise Price, Granted | $ / shares	1.45
Weighted Avg. Exercise Price, Exercised | $ / shares	.00
Weighted Avg. Exercise Price, Forfeited/Cancelled | $ / shares	.00
Weighted Avg. Exercise Price, Outstanding | $ / shares	2.13
Weighted Avg. Exercise Price, Exercisable | $ / shares	$ 2.18
Outstanding - Aggregate Intrinsic Value | $	$ 220,485
Exercisable - Aggregate Intrinsic Value | $	$ 205,055

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Stockholders' Equity (Details 2)	3 Months Ended
	Jul. 31, 2018 $ / shares shares
Options Outstanding	2,607,385
Options Exercisable	2,427,587
Exercise Price Range One [Member]
Exercise Price | $ / shares	$ 1.30
Options Outstanding	12,000
Options Outstanding, Weighted Avg. Life Remaining	6 months
Options Exercisable	12,000
Exercise Price Range Two [Member]
Exercise Price | $ / shares	$ 1.38
Options Outstanding	1,795,958
Options Outstanding, Weighted Avg. Life Remaining	8 years 1 month 2 days
Options Exercisable	1,682,946
Exercise Price Range Three [Member]
Exercise Price | $ / shares	$ 1.40
Options Outstanding	25,703
Options Outstanding, Weighted Avg. Life Remaining	9 years 4 months 20 days
Options Exercisable	25,703
Exercise Price Range Four [Member]
Exercise Price | $ / shares	$ 1.50
Options Outstanding	40,000
Options Outstanding, Weighted Avg. Life Remaining	10 years
Options Exercisable	8,000
Exercise Price Range Five [Member]
Exercise Price | $ / shares	$ 1.98
Options Outstanding	5,000
Options Outstanding, Weighted Avg. Life Remaining	8 years 4 days
Options Exercisable	5,000
Exercise Price Range Six [Member]
Exercise Price | $ / shares	$ 2.00
Options Outstanding	457,402
Options Outstanding, Weighted Avg. Life Remaining	6 years 11 months 1 day
Options Exercisable	431,895
Exercise Price Range Seven [Member]
Exercise Price | $ / shares	$ 2.87
Options Outstanding	65,334
Options Outstanding, Weighted Avg. Life Remaining	6 years 6 months 18 days
Options Exercisable	64,611
Exercise Price Range Eight [Member]
Exercise Price | $ / shares	$ 3.00
Options Outstanding	51,001
Options Outstanding, Weighted Avg. Life Remaining	7 years 4 months 28 days
Options Exercisable	42,445
Exercise Price Range Nine [Member]
Exercise Price | $ / shares	$ 3.39
Options Outstanding	12,000
Options Outstanding, Weighted Avg. Life Remaining	7 years 7 months 20 days
Options Exercisable	12,000
Exercise Price Range Ten [Member]
Exercise Price | $ / shares	$ 6.00
Options Outstanding	10,000
Options Outstanding, Weighted Avg. Life Remaining	6 years 5 months 26 days
Options Exercisable	10,000
Exercise Price Range Eleven [Member]
Exercise Price | $ / shares	$ 12.00
Options Outstanding	132,987
Options Outstanding, Weighted Avg. Life Remaining	5 years 3 months 7 days
Options Exercisable	132,987

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Stockholders' Equity (Details 3)	3 Months Ended
	Jul. 31, 2018 $ / shares shares
Weighted Avg. Exercise Price, Granted	$ 1.45
Stock Purchase Warrants [Member]
Number of Warrants, Outstanding and exercisable, Beginning balance | shares	2,223,669
Number of Warrants, Forfeited | shares	0
Number of Warrants, Granted | shares	0
Number of Warrants, Outstanding and exercisable, Ending balance | shares	2,223,669
Weighted Avg. Exercise Price, Outstanding and exercisable	$ 5.02
Weighted Avg. Exercise Price, Forfeited	.00
Weighted Avg. Exercise Price, Granted	.00
Weighted Avg. Exercise Price, Outstanding and exercisable	$ 5.02
Weighted Avg. Life Remaining, Outstanding and exercisable, beginning	2 years 6 months 25 days
Weighted Avg. Life Remaining, Outstanding and exercisable, ending	2 years 29 days

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Stockholders' Equity (Details Narrative) - USD ($)	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017	Apr. 30, 2018
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	150,000,000		150,000,000
Common stock, par value	$ 0.00001		$ 0.00001
Common stock, shares issued	17,569,733		17,309,733
Common stock, shares outstanding	17,569,733		17,309,733
Unrecognized stock based compensation expense	$ 199,168
Unrecognized Share-based Compensation, Period for Recognition	3 years
Aggregate intrinsic value of warrants	$ 0
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
General and Administrative Expense [Member]
Allocated stock based compensation expense	$ 191,818	$ 529,332

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Revenue from Contracts with Customers (Details) - USD ($)	3 Months Ended
	Jul. 31, 2018	Jul. 31, 2017
Total revenue from customers	$ 574,065	$ 8,803
Oil sales
Total revenue from customers	1,364
Natural gas sales
Total revenue from customers	$ 572,701