Filing Compare · CIRCLE STAR ENERGY CORP.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended APRIL 30, ~~2013~~2014

o 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 000-53868

CIRCLE STAR ENERGY CORP.

(Exact name of registrant as specified in its charter)

Nevada	3098-~~0696883~~05737383
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
7065 Confederate Park Road, Suite 102, Fort Worth, Texas	76108
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (817) 744-8502

Securities registered under Section 12(b) of the Act:

None	None
Title of each class	Name of each exchange on which registered

Securities registered under Section 12(g) of the Act:

Common Stock, $0.001 par value

(Title of class)

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Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

Indicate by checkmark 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 o

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 (§ 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 o

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company x

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $71,~~933~~475,~~368~~651.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. As of August 138, ~~2013,~~2014 we had 5072,~~137~~718,~~916~~044 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	98
Item 1A.	Risk Factors	1611
Item 1B.	Unresolved Staff Comments	1612
Item 2.	Properties	1612
Item 3.	Legal Proceedings	2015
Item 4.	Mine Safety Disclosures	2115
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2216
Item 6.	Selected Financial Data	2317
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	2317
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	2923
Item 8.	Financial Statements and Supplementary Data	3024
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	6051
Item 9A.	Controls and Procedures	6051
Item 9B.	Other Information	6152
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	6253
Item 11.	Executive Compensation	6354
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	6655
Item 13.	Certain Relationships and Related Transactions, and Director Independence	6655
Item 14.	Principal Accounting Fees and Services	6756
PART IV
Item 15.	Exhibits, Financial Statement Schedules	6857

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Forward Looking Statements

This Current Report on Form 10-K contains forward-looking statements. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of any statements containing the words “anticipate,” “intend,” “believe,” “estimate,” “project,” “expect,” “predict,” “plan,” “should,” “likely,” “may,” “will,” “continue” or similar expressions are intended to identify such statements. All statements other than statements of historical facts that address activities that we intend, expect or anticipate will or may occur in the future are forward-looking statements. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty. Forward-looking statements relate to, among other things:

·• our strategies, either existing or anticipated;

·• our future financial position, including anticipated liquidity;

·• our ability to satisfy obligations from cash generated from operations;

·• amounts and nature of future capital expenditures;

·• acquisitions and other business opportunities;

·• operating costs and other expenses, including asset retirement obligation expenses;

·• wells expected to be drilled, other anticipated exploration efforts and associated expenses;

·• estimates of proved oil and natural gas reserves, deferred tax assets, and depletion rates;

·• our ability to meet additional acreage, seismic and/or drilling cost requirements; and

·• other estimates and assumptions we use in our accounting policies.

Factors that could cause actual results to differ materially from our expectations include, among others, such things as:

·• loss of our sole officer and director;

·• oil and natural gas prices and production costs;

·• our ability to replace oil and natural gas reserves, including changes in reserve estimates resulting from expected oil and gas prices, production rates, tax rates and production costs;

·• exploitation, development, production and exploration results, including mechanical failure;

·• the estimated costs of asset retirement obligation, including whether or not those retirement costs, in whole or in part, are ever actually incurred in the future;

·• the potential unavailability of drilling rigs and other field equipment and services;

·• the existence of unanticipated liabilities relating to existing properties or those acquired in the future, including environmental liabilities;

·• factors affecting the nature and timing of our capital expenditures, including the availability of service contractors and equipment;

·• the willingness and ability of third parties to honor their contractual commitments;

·• permitting issues;

·• the nature, extent and duration of workovers;

·• the impact and costs related to compliance with or changes in laws governing our operations;

·• acquisitions and other business opportunities (or the lack thereof) that may be pursued by us;

·• competition for properties and the effect of such competition on the price of those properties;

·• economic, market or business conditions, including any change in interest rates or inflation;

·• the lack of available capital and financing;

·• risk factors consistent with comparable companies within our industry, especially companies with similar market capitalization and/or employee census; and

·• weather or other factors, many of which are beyond our control.

Furthermore, forward-looking statements are made based on our current assessment available at the time. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to our expectations and intentions and, thus, we may alter our plans regarding any exploration and development activities.

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Although we believe that the expectations reflected in such forward-looking statements are reasonable, those expectations may prove to be incorrect. As with comparable companies within our industry, there are numerous factors that could cause actual results to differ materially from our expectations. All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

This list is not an exhaustive list of the factors that may affect any of our forward-looking statements. These and other factors should be considered carefully and readers should not place undue reliance on our forward-looking statements.

Our financial statements are stated in United States dollars and are prepared in accordance with United States generally accepted accounting principles.

In this annual report, unless otherwise specified, all dollar amounts are expressed in United States dollars and all references to "common stock" refer to the common shares in our capital stock.

As used in this annual report, the terms “we”, “us”, “our”, the “Company” and “Circle Star” mean Circle Star Energy Corp., unless otherwise indicated.

GLOSSARY OF TERMS

Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report:

Terms used to describe quantities of crude oil and natural gas:

“Bbl” – Barrel or 42 U.S. gallons liquid volume.

“BOE” – Barrels of crude oil equivalent.

“Condensate” – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Mcf” – Thousand cubic feet of gas.

“NGLs” – Natural gas liquids.

Terms used to describe our interests in wells and acreage:

“Gross acres” – The number of acres in which we own a gross working interest.

“Gross well” – A well in which we own a working interest.

“Net acres” – Our percentage ownership of gross acreage. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“Net well” – Deemed to exist when the sum of fractional ownership working interests in gross wells equals one.

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“Developed acreage” – Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Development well” – A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.

“Disposal well” – A well-used for the disposal of water resulting from the production of oil and gas. Oil and gas reservoirs are usually found in porous rocks, which also contain saltwater. This saltwater, which accompanies the oil and gas to the surface, is disposed over time through injection into underground porous rock formations not productive of oil or gas.

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“Dry hole” – An exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

“Exploratory well” – A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.

“Injector well” – A well-used for the injection of water, gas, steam or CO2 into an oil-or gas producing reservoir/unit in order to maintain reservoir pressure, heat the oil or lower its viscosity, in order to increase oil and /or gas recovery and to safely dispose of the salt and/or fresh water produced with oil and natural gas.

“Productive well” – An exploratory or a development well that is not a dry hole.

“Undeveloped acreage” – Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.

“Unproved property” – A property or part of a property with no proved reserves.

“Unsuccessful efforts” – Drilling activities that result in a dry hole. Costs associated with unsuccessful efforts are part of the cost to discover reserves, therefore are capitalized in the full cost pool.

Terms used to describe seismic activity and operations:

“Fracturing” – The injection of water, sand and additives under hydraulic pressure into prospective rock formations at depth to stimulate oil and natural gas production.

“Horizontal Drilling” – A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontal within a designated zone typically defined as the prospective pay zone to be completed for oil and/or gas.

“Hydraulic stimulation technology” – A synonym for “fracturing.” A process that results in the creation of fractures in rocks. The fracturing is done from a wellbore drilled into reservoir rock formations at depth to increase the rate and ultimate recovery of oil and natural gas.

“Plugging and abandonment” – The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

“Recompletion” – The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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“Workover” – Operations on a producing well to restore or increase production.

Terms used to describe the legal ownership of our oil and natural gas properties:

“Revenue interest” – The amount or percentage of revenue/proceeds derived from a producing well that the owner is entitled to receive.

“Working interest” – The amount or percentage of costs that an owner is required to pay of drilling and production expenses. It also gives the owners, in the aggregate, the right to drill, produce and conduct operating activities on the property.

Terms used to assign a present value to or to classify our reserves:

“PV-10” – The estimated future cash flow, discounted at a rate of 10% per annum, with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

“Proved developed non-producing reserves” – ~~Proved~~Reserves ~~crude~~include ~~oil~~shut-in and ~~natural gas reserves that are developed~~ behind -pipe, ~~shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor~~reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells ~~that~~which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, ~~that~~which will require additional completion work or future recompletion prior to the start of production.

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“Proved developed reserves” – Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved reserves” – Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves” – Proved crude oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.

“Probable” - Reserves are those additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will equal or exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there must be a least a 50% probability that the actual quantities recovered with equal or exceed the proved plus probable reserves estimates.

“Possible” - Reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there must be at least a 10% probability that the actual quantities recovered will equal or exceed the sum of proved, probable, and possible estimates.

“Standardized Measure” – The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

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Other Terms:

“Farmout” – An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farmin" while the interest transferred by the assignor is a "farmout."

“Field” – An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

“Play” – An accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.

“Prospect” – A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce.

“Reservoir” – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Resources” – Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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PART I

Item 1. Business

History and Overview

The Company was incorporated on May 21, 2007. Through June 2011, we had limited operations primarily focused on organizational matters and developing an online help desk customer support system to assist service companies to improve their customer relationship management. In fiscal 2011, we began to explore opportunities to diversify our business. On June 16, 2011, the Company filed a Certificate of Amendment to its articles of incorporation with the Secretary of State of Nevada changing the name of the Company from Digital Valleys Corp. to Circle Star Energy Corp., effective July 1, 2011. Effective July 1, 2011, the Company’s ticker symbol on the OTCBB was changed from “DTLV” to “CRCL.”

In May 2011, management of the Company decided to pursue new business opportunities in oil and gas exploration and development. Shortly thereafter, the Company closed several acquisitions of interests in oil and gas properties:

JHE Acquisition

On June 16, 2011, the Company ~~closed~~acquired anall ~~acquisition~~of ~~under~~ the ~~terms~~membership ofinterests ain ~~Membership Interest Purchase Agreement, effective as of June 1, 2011 (the “~~JHE ~~Purchase Agreement”)~~Holdings, ~~between High Plains Oil,~~ LLC, a ~~Nevada~~Texas limited liability company (“~~High Plains~~JHE”), ~~and~~effective ~~JHE~~as ~~Holdings,~~of ~~LLC~~June ~~(“JHE”)~~1, ~~pursuant~~2011, tofrom ~~which~~High ~~the~~Plains ~~Company~~Oil, ~~acquired all of the membership interests in JHE~~LLC, a ~~Texas~~Nevada limited liability company ~~from High Plains~~ (~~the~~ “~~JHE~~High ~~Acquisition~~Plains”). High Plains is an entity controlled by S. Jeffrey Johnson (“Johnson”), who was appointed as a director of the Company on June 16, 2011 and Chairman of the Board on July 6, 2011. Johnson was at ~~arms~~arm’s length to the Company prior to his appointment as a director. The consideration for JHE included the issuance of 1,000,000 shares of the Company’s common stock to High Plains, a 10% retained profits interest in JHE to be retained by High Plains, the assumption of a promissory note in the aggregate amount of $7,500,000, and the issuance of 600,000 shares of the Company’s common stock to the holders of the assumed note.

InThe ~~consideration~~assumed ~~for~~promissory ~~the~~note ~~acquisition~~was secured by all of the membership interests in JHE, and was fully paid by the Company ~~agreed~~as tofollows: cash payments of $1,000,000 in June 2011, $1,500,000 in September 2011, $2,000,000 in February 2012, $1,500,000 in April 2012, and $1,250,000 in June 2012, and the conveyance of certain interests in properties held by JHE in June 2012.

(a) issue 1,000,000 shares of its common stock (“Common Shares”) to High Plains (the “High Plains Consideration Shares”);

(b) pay the $1,000,000 installment payment due June 1, 2011, under a promissory note in the aggregate amount of $7,500,000 (the “Edsel Promissory Note”) issued by High Plains to James H. Edsel, Nancy Edsel, and James H. Edsel, Jr. (collectively, the “Edsels”) in connection with the acquisition of JHE by High Plains from the Edsels that closed on March 30, 2011 and was effective as of January 2011 (the “High Plains Acquisition”);

(c) execute and deliver a Novation and Assignment Agreement (the “Novation”) pursuant to which the Company would, effective June 1, 2011 (the “JHE Effective Date”): (i) assume all of the obligations and liabilities of High Plains under the Edsel Promissory Note, and (ii) in consideration for, among other things, consenting to the Acquisition and the forbearance by the Edsels of the first installment payment of $1,000,000 due under the Edsel Promissory Note on June 1, 2011 until June 10, 2011 or the closing date, issue an aggregate of 600,000 Common Shares to the Edsels (the “Edsel Shares”);

(d) undertake to cause JHE to amend its limited liability company agreement to, among other items, provide for the retention by High Plains of a 10% contractual profits interest in JHE (the “Retained Profits Interest”) in the form of a right to 10% of the net revenues, payments, royalties and other distributions received by JHE from the JHE Oil and Gas Properties, as defined below;

(e) execute and deliver an Amended and Restated Pledge and Security Agreement (the “Amended Pledge Agreement”) with the Edsels pursuant to which the Company would, effective as of the JHE Effective Date: (i) assume all of High Plains’ obligations and liabilities under the initial Pledge and Security Agreement entered into by and between High Plains and the Edsels in connection with the issuance of the Edsel Promissory Note as partial consideration in respect to the High Plains Acquisition and (ii) undertake to cause JHE to assign and transfer a 10% interest in the JHE Oil and Gas Properties to High Plains in exchange for the Retained Profits Interest upon full and complete payment and satisfaction of all obligations due under the Edsel Promissory Note and Amended Pledge Agreement;

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(f) undertake to cause JHE to make a distribution to High Plains, within five (5) business days of June 30, 2011, of cash remitted to JHE through and including June 30, 2011; and

(g) pay Pimuro, a consultant who advised High Plains with regards to its acquisition of JHE and the Purchase Agreement, the accrued fees and expenses in the amount of $240,000 relating to such consulting arrangement between High Plains and Pimuro under the terms of an Installment Agreement (the “Installment Agreement”), payable of $100,000 on the closing date and thereafter in monthly installments of $50,000, $50,000 and $40,000 commencing when JHE received $75,000 in monthly aggregate distribution from JHE Oil and Gas Properties (defined below). Pimuro is controlled by G. Jonathan Pina (“Pina”), who was appointed as our Chief Financial Officer on July 11, 2011. Pina was at arms’-length to the Company prior to his appointment.

The acquisition of JHE by the Company closed on June 16, 2011.

Redfish Properties Acquisition

On December 6, 2011, the Company ~~entered~~acquired into a letter agreement (the “Apache Letter Agreement”) with Ingebritson Energy LLC, GTP Energy Partners, LLC, Wind Rush Energy, LLC, Gabriel Barerra and Charles T. Brackett (collectively, the “Apache Sellers”) with a stated execution date of December 1, 2011 (the “Apache Execution Date”). The Letter Agreement was effective November 1, 2011. Pursuant to the Apache Letter Agreement, the Company purchased from the Apache Sellers certain interests in oil and gas properties within the Redfish 56 Prospect in Glasscock County, Texas., Ineffective ~~return~~November 1, ~~the~~2011, ~~Apache~~in ~~Sellers~~consideration ~~received~~for 203,571 ~~Common~~shares ~~Shares~~of the Company’s common stock and the ~~Company~~assumption ~~assumed~~of the responsibility for payment of certain operating expenses and capital expenditures.

Colonial Divestiture

The Company entered into a Membership Interest Purchase Agreement with Colonial Royalties, LLC (“Colonial”) on December 30, 2011 (the “Colonial Purchase Agreement”), whereby Colonial would purchase 100% of the Company’s interests in JHE and the Retained Profits Interest, held by High Plains (the “Colonial Transaction”), in consideration for $9,350,000. The first payment, $100,000, was received on December 30, 2011.

On February 6, 2012, the Company sent a Notice of Default and Termination (the “Colonial Notice”) to Colonial stating that Colonial was in breach of its payment obligations under the Colonial Purchase Agreement and that the Company was exercising its right to terminate the Colonial Purchase Agreement. Under the terms of the Colonial Purchase Agreement, the delivery of the Colonial Notice by the Company to Colonial was not deemed to be an election of remedies and the Company retained the right to pursue all legal or equitable remedies against Colonial for breach of the Colonial Purchase Agreement.

Wevco Acquisition

On March 6, 2012, the Company entered into a leasehold Purchase Agreement with Wevco Production, Inc. (“Wevco”), whereby Wevco would sell to the Company all of Wevco’s rights, title, and working interest in and to certain oil and gas leases, containing up to 64,575 net acres, situated in Gove and Trego Counties, Kansas (the “Wevco Purchase Agreement”). Under the Wevco Purchase Agreement, the Company was to pay $5,000,000 on or before closing and issue 1,000,000 ~~Common~~shares ~~Shares~~of the Company’s common stock to the seller. At the time of the signing of the Purchase Agreement, the Company paid $100,000 and the Company paid an additional $200,000 in March 2012 (collectively, the “Wevco Signing Bonus”). These amounts were non-refundable and were considered an advance against the Purchase Price. The Company issued the 1,000,000 ~~Common~~common ~~Shares~~shares in March 2012.

OnThe ~~April 24, 2012, the~~ Company entered into antwo ~~amendment~~amendments to the Wevco Purchase Agreement ~~extending~~to extend the original April 30, 2012 closing date ~~from~~to ~~April~~September 3028, 2012 ~~until~~and ~~May~~paid 31a total of $200,000 ~~2012~~in (extension fees and issued 600,000 shares of the ~~“Wevco~~Company’s ~~First~~common ~~Amendment”)~~stock. As ~~The~~of ~~Company~~July ~~paid~~31, a2012, ~~non-refundable~~the Company had capitalized $~~100~~3,~~000~~611,638 ~~extension~~in ~~fee~~costs ~~which~~as ~~was~~deposits ~~considered~~subject anto ~~advance~~forfeiture ~~against~~related ~~the~~to ~~Purchase~~consideration ~~Price~~paid to the seller.

OnThe ~~June~~Company ~~13,~~did ~~2012,~~not fully execute the ~~Company~~terms ~~entered~~of ~~into~~the apurchase ~~Second~~agreement ~~Amendment~~by toSeptember ~~Purchase~~28, ~~Agreement~~2012. ~~extending~~The ~~the~~Seller ~~closing~~assigned ~~date~~1,120 ~~from~~of ~~May~~the 3164,575 ~~2012~~net ~~until~~acres ~~September~~stipulated ~~28,~~in ~~2012~~the (initial purchase agreement to the ~~“Second~~Company ~~Amendment”)~~in October 2012. ~~Pursuant~~The tovalue of the ~~Second~~acreage ~~Amendment,~~transferred to the Company ~~paid~~relative ato ~~non-refundable~~the ~~$100~~initial 64,~~000~~575 ~~extension~~net ~~fee~~acres ~~and~~as ~~issued~~per ~~600,000~~the ~~Common~~terms ~~Shares.~~of ~~The~~the ~~shares~~initial ~~were~~Purchase ~~issued~~Agreement onamounted ~~June~~to 19$62,641. ~~2012~~These atcosts ahave ~~price~~been oftransferred ~~$0.89~~to ~~per~~unproved ~~share.~~properties Ason the Company’s consolidated balance sheet as of ~~July~~April 3130, ~~2012,~~2014 and the ~~Company~~remaining ~~had capitalized~~ $3,~~611~~548,~~638~~997 inof ~~costs as~~ deposits subject to forfeiture ~~related~~have tobeen ~~consideration~~charged ~~granted~~to ~~the~~impairment ~~seller~~expense.

10On December 18, 2012, the Company and Wevco executed a Settlement and Release Agreement (“Release”). In connection with the execution of the Release, the Company issued 225,000 shares of its Common Stock to Wevco at $0.38 per share. The shares were issued as follows: 115,965 shares in consideration for the satisfaction of $44,066 in accrued liabilities due Wevco and 109,035 shares in consideration for approximately 1,400 acres Wevco assigned to the Company. As of April 30, 2014 we have drilled three wells on this acreage.

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The Company did not fully execute the terms of the purchase agreement by September 28, 2012. The Seller assigned 1,120 of the 64,575 net acres stipulated in the initial purchase agreement to the Company in October 2012. The value of the acreage transferred to the Company relative to the initial 64,575 net acres as per the terms of the initial Purchase Agreement amounted to $62,641. These costs have been transferred to unproved properties on the Company’s consolidated balance sheet as of April 30, 2013 and the remaining $3,548,997 of deposits subject to forfeiture have been charged to impairment expense.

On December 18, 2012, the Company and Wevco executed a Settlement and Release Agreement (“Release”). In connection with the execution of the Release the Company issued 225,000 Common Shares to Wevco at $0.38 per share. The Common Shares were issued as follows; 115,965 in consideration for the satisfaction of $44,066 in accrued liabilities due Wevco and 109,035 in consideration for approximately 1,400 acres Wevco assigned to the Company.

BlueRidge Acquisition

On April 17, 2012, the Company agreed to purchase certain interests in oil and gas leases in Rawlins, Sheridan and Graham Counties, Kansas for $5,308,375 and 560,000 ~~Common~~common ~~Shares~~shares, with a closing date of July 1, 2012. Pursuant to the Purchase Agreement, the Company initially agreed to purchase interests in 17,168 acres in Rawlins County, 12,518 acres in Sheridan County and 12,781 acres in Graham County. The Company also paid $50,000 in irrevocable earnest money to be applied to the purchase price at closing.

The Purchase Agreement was amended on July 2, 2012 by which the terms were modified by reducing the acreage of the leases in Graham County by 1,760 acres, and by granting the Company an option to purchase the properties in Rawlins and Graham Counties. The amendment further modified the terms of the Purchase Agreement, whereby the $50,000 of earnest money previously paid was applied to the purchase price and the Company issued 2,611,000 ~~Common~~shares ~~Shares~~of the Company’s common stock to the ~~certain~~ sellers, for the interests in Sheridan County. The shares were issued on July 19, 2012 at a price of $0.70 per share. The Company did not exercise the option to purchase the properties in Rawlins and Graham Counties.

~~Pursuant~~As the Company did not exercise its right to exercise its purchase option, the ~~amendment~~$50,000 in cash paid and the ~~Company~~value ~~had~~of the ~~option~~shares to$1,868,632, ~~purchase~~were ~~interests~~reclassified infrom ~~80,871~~non-refundable ~~acres~~lease indeposits ~~Kansas~~to ~~(including~~unproved property costs during the ~~properties~~quarter inended October 31, 2012. During the ~~Rawlins~~fiscal ~~and~~year ~~Graham~~ended ~~Counties~~April ~~described~~30, ~~above)~~2013 $946,895 byof ~~making~~the costs were impaired related to a ~~cash~~transfer ~~payment~~of 50% of ~~$10,108,875~~the ~~and~~subject byacreage ~~delivering~~related to the ~~number~~settlement of ~~Common~~litigation ~~Shares~~related ~~equal~~ to this matter in addition $1238,~~000,000,~~880 ~~based~~of on the ~~market~~costs ~~price~~related ofto the ~~Common~~acreage ~~Shares~~were onimpaired ~~the~~related ~~date~~to ~~before~~lease ~~closing~~expirations. ofDuring the ~~Option~~fiscal year ended April 30, on2014 orthe ~~before~~remaining ~~September~~value ~~28,~~of ~~2012.~~the ~~The~~lease ~~Company~~acreage ~~did~~was ~~not~~impaired ~~exercise~~related ~~this~~lease ~~option~~expirations.

~~Edsel~~Circle ~~Promissory~~Star ~~Note~~Operating

~~Pursuant~~Circle toStar ~~the~~Operating ~~Amended Pledge Agreement~~Corp., ~~the~~a ~~Company,~~Nevada ~~effective~~corporation as(“CSOP”) was offormed ~~the~~on ~~JHE~~June ~~Effective Date~~12, ~~pledged~~2012. ~~100%~~Through ofCSOP ~~the~~we ~~membership~~have ~~interests~~entered ininto ~~JHE~~several toparticipation ~~the~~agreements ~~Edsels,~~whereby ~~including~~we ~~all~~have ~~rights~~drilled and ~~assets~~are ~~relating to such membership interests, as security for~~ the ~~payment~~operator ~~and~~of ~~satisfaction~~record of ~~the~~three ~~Company’s~~wells ~~obligations~~in ~~under~~Trego ~~the~~County, ~~Edsel Promissory Note~~Kansas.

The JHE Oil and Gas Properties constituted material assets of the Company such that if the Company defaulted under the Edsel Promissory Note and the Edsels satisfied the Company’s obligations under the Edsel Promissory Note by selling the unvested portion of the membership interests, the Company could lose all or a portion of the JHE Oil and Gas Properties. In accordance with terms of the JHE Purchase Agreement, as consideration for the acquisition of JHE from High Plains, the Company entered into the Novation pursuant to which the Company agreed to assume, effective as of the JHE Effective Date, all of High Plains’ obligations and liabilities under the Edsel Promissory Note. The Edsel Promissory Note had an initial principal balance of $7,500,000, $1,000,000 of which was paid at closing as consideration for the acquisition of JHE by the Company, and bore interest at a rate of 5% per annum. At closing, the principal balance of the Edsel Promissory Note was $6,500,000 payable on scheduled installments.

On September 2, 2011, the Company paid $400,000 of the $1,500,000 installment due on September 1, 2011 for the Edsel Promissory Note and received an extension from the Edsels to pay the balance of the payment on or before September 15, 2011. The Company paid the balance of the installment payment prior to September 15, 2011.

The Company was unable to timely make the $2,000,000 December 2011 Edsel Payment to the Edsels due on December 31, 2011, and in consideration of a payment in the amount of $100,000 by the Company to the Edsels and pursuant to a letter agreement dated December 29, 2011, the Edsels agreed to extend the payment date for the December 2011 Edsel Payment until January 31, 2012, on which date the December 2011 Payment was due and payable. The Company was unable to timely make the extended payment to the Edsels on January 31, 2012 and as consideration for the Edsels agreeing to (i) further extend the due date for the December 2011 Payment until February 8, 2012 and (ii) extend the due date for March 2012 Edsel Payment until April 30, 2012 (collectively, the “Modified Payment Terms”), the Company offered to pay, among other items, the sum of $2,000,000 to the Edsels as a principal payment under the Edsel Promissory Note on or before February 8, 2012 pursuant to the terms of a letter agreement dated February 8, 2012. Concurrently therewith, and as additional consideration for the Modified Payment Terms, the Company also agreed to execute the Edsel Amendments, which are described in more detail below.

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On February 8, 2012, the Company made the $2,000,000 December 2011 Payment due to the Edsels under the Edsel Promissory Note.

On February 8, 2012, the Company entered into a First Amendment to Assignment and Novation Agreement and a First Amendment to Membership Interest Pledge and Security Agreement (collectively, the “Edsel Amendments”) pursuant to which the Company agreed to delete provisions from each of the Novation and the Amended Pledge Agreement which provided for, among other items, the vesting, and release from any transfer restrictions, of a corresponding portion of the Company Oil and Gas Properties, as defined in the Novation and Amended Pledge Agreement, once at least fifty percent (50%) of the original principal amount of the Edsel Promissory Note had been paid to the Edsels and thereafter as each further payment of principal was made by the Company to the Edsels under the Edsel Promissory Note. Except as expressly set forth in the Edsel Amendments, all of the terms and provisions of the Novation and Amended Pledge Agreement were unchanged and remained in full force and effect.

Effective February 8, 2012, the Company entered into an Inter-Creditor Agreement (the “Inter-Creditor Agreement”) with the holders of the February 10% Notes (as defined below – see Financings). The Inter-Creditor Agreement provided for, among other items, (i) the grant to the holders of the 10% Notes of a pledge and security interest in all of the membership interests and assets of JHE, upon termination of the existing pledge and security interest in all of the membership interests and assets of JHE and (ii) the grant on a pro rata basis to the holders of the 10% Notes (based on the ratio of each holder’s investment relative to the aggregate proceeds of the 10% Note Issuance) of a 3.5% overriding royalty interest in certain properties which may be acquired by the Company. (See Financings below for additional information).

The payment of $1,500,000 due on April 30, 2012 was paid on time. Effective June 1, 2012, the Edsels and Circle Star entered into a Note Payment Agreement (the “Note Payment Agreement”, whereby, Circle Star paid the Edsels $1,250,000 and conveyed to Orbis Energy, Ltd. (“Orbis”) certain interests in properties held by JHE that were operated by Encana (“Encana Properties”). The payment of $1,250,000 and the conveyance of the Encana Properties resulted in the Edsel Promissory Note being fully paid, and the Company was released from any further obligations to the Edsels under the Edsel Promissory Note, the Amended Pledge Agreement and the Novation.

Financings

On June 15, 2011, the Company closed a private placement of units. Under the terms of the private placement, the Company issued 4,800,000 units at a price of $0.25 per unit. Each unit consisted of one Common Share and one Common Share purchase warrant, which was exercisable to acquire one Common Share at an exercise price of $0.50 through June 15, 2013.

On August 17, 2011, the Company closed a private placement of Common Shares. Under the terms of the private placement, the Company issued 1,440,000 Common Shares at a price of $0.25 per share to “Accredited Investors” (as defined in Rule 501(a) of the United States Securities Act of 1933, as amended (the “Securities Act”).

On September 14, 2011, the Company issued 6% convertible notes (the “6% Notes”) in the total amount of $1,500,000 (the “6% Note Issuance”). The 6% Notes are due and payable on September 14, 2014, with interest at the rate of 6% per annum accruing on the unpaid principal amount, compounded annually. The 6% Notes are convertible at the option of the holder into Common Shares at a conversion price of $1.50 per share. The 6% Notes are redeemable prior to maturity at the option of the Company and can be repaid in whole or in part at any time without a premium or penalty, upon 5 business days’ notice; prior to which the holder of the 6% Note may convert the principal and interest into Common Shares. The proceeds of the 6% Note Issuance went to pay the balance of the $1,500,000 installment due on September 1, 2011 for the Edsel Promissory Note (see Edsel Promissory Note above for more additional information).

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On March 14, 2012, the Company issued 10% convertible notes (the “March 10% Notes”) for cash in the aggregate principal amount of $500,000 (the “March 10% Note Issuance”), subject to the terms of the Addendum (as defined below). The March 10% Notes accrued interest at the rate of 10% per annum on the unpaid principal balance and could be repaid by the Company at any time without the prior written consent of the holders. The March 10% Notes were due and payable on March 14, 2013 (the “March 10% Maturity Date”) or at the election of the holder on the earlier of (i) the closing of a financing transaction by the Company for aggregate proceeds in excess of $5,000,000, which excess amount shall be applied to the principal balance of the holder’s March 10% Note; (ii) the sale or partial sale of JHE; (iii) the sale of all or substantially all of the assets of JHE; or (iv) an Event of Default (as defined in the March 10% Notes). The March 10% Notes were convertible at the option of the holder into Common Shares at the March 10% Maturity Date or upon the occurrence of one or more of the triggering events set forth in clauses (i), (ii), and (iii) above, at a conversion price of $1.50 per share. The proceeds of the March 10% Notes were used to pay the Wevco Signing Bonus. The balance of the proceeds of the March 10% Notes were used for other general corporate purposes.

Effective March 14, 2012, the Company entered into an Addendum to March 2012 Convertible Note Subscription Agreement (the “Addendum”) with the holder of the March 10% Notes. The Addendum provided for, among other items, the Company to use its best efforts to (i) the grant to the holder of the March 10% Notes of a subordinated security interest in JHE, upon termination of the then existing pledge and security interest JHE and any creditor with a senior security interest or right to a security interest in JHE existing as of the date of the Addendum; (ii) grant a security interest in the Company’s interest in certain oil and gas properties within the Redfish 56 Prospect in Glasscock County, Texas; and (iii) upon issuance of the Pina Bonus Shares (as defined below in Item 11. “Executive Compensation”), under the terms of the Pina Employment Agreement (as defined below in Item 11. “Executive Compensation”), as may be amended from time to time, Pina would pledge the Pina Shares (as defined below in Item 11. “Executive Compensation”) to secure payment of the March 10% Notes.

As of April 30, 2012, the Company issued 4,800,000 Common Shares in connection with the exercise of 4,800,000 share purchase warrants at $0.50 per share. The Company received $2,400,000 in proceeds of which $1,200,000 was received in April 2012 and $1,200,000 in May 2012. The warrants had been issued on June 15, 2011 in a private placement by the Company of 4,800,000 units at a price of $0.25 per unit, each unit consisted of one Common Share and one Common Share purchase warrant, exercisable to acquire one Common Share at an exercise price of $0.50 through June 15, 2013.

On May 15, 2012, the Company closed a private placement of units to an Accredited Investor. Under the terms of the private placement, the Company issued 500,000 units at a price of $1.50 per unit. Each unit consisted of one Common Share and one half Common Share purchase warrant, each full warrant exercisable to purchase one Common Share at $2.75 for a period of three years. $750,000 was raised by the Company in the private placement. The proceeds were partially used to pay the final payment of the Edsel Promissory Note, the June Extension Price and general corporate purposes.

Strategy

Our primary objective is to increase our net asset value, and cash flow through acquisitions, exploration, development, and exploitation of oil and gas properties.

The four key components of our growth strategy are:

●· Identification and acquisition of strategic assets. ~~● Utilization of strategic partners. ● Cost effective implementation of operations. ● Increase cash flows from existing properties.~~

13· Utilization of strategic partners.

~~Table~~· Cost effective implementation of ~~Contents~~operations.

·	Increase cash flows from existing properties.

On-Going Activities

Texas

The Company owns a variety of non-operated working interests and overriding royalty interests in approximately 7361 producing wells in Texas. The interests range from less than 1% up to approximately 5% in each well. The wells are located in the following areas: Permian Basin, Eagle Ford Shale, Pearsall Field, Giddings Field &and the Woodbine Field. The wells are operated by Apache (Permian), ~~Chesapeake~~EXCO (Eagle Ford Shale), CML (Giddings, Pearsall &and Permian), Leexus (Giddings) and MD ~~Woodbine~~America ~~Acquisitions~~Energy, LLC. (Woodbine). As of April 30, ~~2013~~2014, the Company had approximately 430 net leased acres in Texas.

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Kansas

The Company operates 23 producing wells in Trego County, Kansas. The Company owns between a 25% ~~working interest (approximately 20% net revenue interest) before payout~~ and ~~a 43.75~~55% working interest ~~(approximately 35% net revenue interest) after payout~~ in ~~both~~these ~~wells~~three ~~which are located in Trego County~~wells. As ofSubsequent ~~April~~to ~~30, 2013,~~ the ~~Company~~end had approximately 13,998 net leased acres in Kansas. Approximately 1,480 are located in Trego County and approximately 12,518 are located in Sheridan County. There are multiple potential pay zones of ~~interest with~~ the ~~primary~~fiscal ~~zones~~year ~~of interest being~~ the ~~Arbuckle,~~ ~~Marmaton~~Company &has ~~Lansing-Kansas~~drilled ~~City~~an ~~ranging~~additional ~~from approximately 3~~well,~~200~~ ~~feet~~which tois ~~approximately~~currently ~~4,300 feet in depth~~producing.

The Company had approximately 6,120 net leased acres in Kansas, of which approximately 1,440 are located in Trego County and approximately 4680 are located in Sheridan County. There are multiple potential pay zones of interest with the primary zones of interest being the Arbuckle, Marmaton and Lansing-Kansas City ranging from approximately 3,200 feet to approximately 4,300 feet in depth.

Reserves

During the year ended April 30, ~~2013~~2014, our proved reserves in BOE ~~and~~increased ~~PV-10~~to ~~decreased~~69,710 ~~approximately~~from ~~28%~~51,940 ~~while~~or ~~our~~34% ~~proved~~and ~~reserves in~~ PV-10 ~~increased~~decreased ~~9%,~~ from ~~April~~$2,339,680 30to $1,633,576 ~~2012~~a decrease of approximately 30%. Additional information about our reserves and the calculation of reserves may be found in Item 2., “Properties”.

Contemplated Activities

We are continually evaluating other drilling and acquisition opportunities for possible participation. The absence of news and/or press releases should not be interpreted as a lack of development or activity. Generally, at any one time, we are engaged in various stages of evaluation in connection with one or more drilling or acquisition opportunities. Unless required by applicable law, our policy is generally to not disclose the specifics of any such opportunity until such time as that transaction is finalized, and we have entered into a definitive agreement regarding the same and then, only when such transaction is material to our business. Similarly, we do not speculate on the outcome of such ventures until the drilling, production or other results are available and have been verified by us.

We may alter or vary all or part of these contemplated activities based upon changes in circumstances, including, but not limited to, unforeseen opportunities, inability to negotiate favorable acquisitions, farmouts, joint ventures, or divestitures, commodity prices, lack of cash flow, lack of funding, and/or other events which we are not able to anticipate.

Segment Information and Major Customers

Industry segment

We are engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, and development for and of crude oil and natural gas. While we operate a small number of oil wells, we do not own or operate any gas gathering or processing plant facilities nor do we possess sufficient volume on any pipeline to market our product to end users. All of our operations are conducted in the United States. Consequently, we presently report under a single industry segment.

Markets

We are a small company and, as such, have no impact on the market for our product and little control over the price received. Markets for crude oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including other sources of production, competitive fuels and proximity and capacity of pipelines or other means of transportation, seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our oil and natural gas production is sold at prevailing wellhead prices, subject to additional charges customary to an area.

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The oil and gas business is not generally seasonal in nature, although unusual weather extremes for extended periods may increase or decrease demand for oil and natural gas products temporarily. Additionally, catastrophic events, such as hurricanes or other supply disruptions, may also temporarily increase the demand for oil and gas supplies from areas unaffected by supply disruptions. Such events and their impacts on oil and gas commodity prices may cause fluctuations in quarterly or annual revenue and earnings.

Major Customers

During the year ended April 30, ~~2013~~2014, approximately 8988% of our oil and natural gas production revenues were received from sales through two operators. In the case of bankruptcy of either of these operators it has been estimated that the reduction in annual revenue could be significant. We do not anticipate the loss of either of these operators,; however, cessation of service would cause a material adverse impact on the Company’s results from operations.

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Competition

The oil and gas industry is a highly competitive and speculative business. We encounter strong competition from major and independent oil companies in all phases of our operations. In this arena, we must compete with many companies having financial resources and technical staffs significantly larger than our own. Rather than incur the time and expense to develop in-house capability, we chose to enter joint ventures with other companies having such resources to accelerate our efforts. Competition is intense with respect to acquisitions and the purchase of large producing properties. Due to the limited capital resources available to us, we have historically focused our operations on relatively smaller projects and/or participating with other oil and gas companies. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Government Regulations

Our company is affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing well spacing, air emissions, water discharges, reporting requirements, endangered species, marketing, prices, taxes, allowable rates of production and the plugging and abandonment of wells, the subsequent rehabilitation of the well site locations, occupational health and safety, control of toxic substances, and other matters involving environmental protection. These laws are continually changing and, in general, are becoming more restrictive. We have expended, and expect to expend in the future, significant funds to comply with such laws and regulations. Changes to current local, state or federal laws and regulations in the jurisdictions where we operate could require additional capital expenditures and result in an increase in our costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could impact the economics of our projects.

Employees

As of April 30, ~~2013~~2014, the Company had three full time employees.

Environmental Matters

We are subject to various federal, state, regional and local laws and regulations related to the discharge of materials into, and the protection of, the environment. These laws and regulations, among other things, may impose a liability on the owner or the lessee for the cost of pollution cleanup resulting from operations, subject the owner or lessee to a liability for pollution damages, require the suspension or cessation of operations in affected areas and impose restrictions on injection into subsurface formations in order to prevent the contamination of ground water.

While the Company may engage in hydraulic fracturing activities, this method of stimulating oil and gas production has been in use since the 1940s, and is a common and proven technology used in exploration and production by the oil and gas industry in all oil and gas producing states without any known or significant risks to the environment. In this regard, it should be noted that the Environmental Protection Agency amended the Underground Injection Control provisions of the federal Safe Drinking Water Act to exclude hydraulic fracturing from the definition of “underground injection.” Furthermore, each state has comprehensive laws and regulations to provide for safe well construction practices and operations to ensure the protection of drinking water sources. To our knowledge, the Company is, and remains, in compliance with all federal, state, regional and local provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. With regards to the magnitude of our use of hydraulic fracturing of oil &and gas wells, the Company holds a minority interest in a number of wells that are under the management and control of far larger companies who apply various stimulation strategies. With these small interests, in the unlikely event that a containment failure were to occur on a single well, it is not likely that the event would have a material financial or operational impact on the Company.

15Potential environmental effects may also arise from the use of disposal and injector wells. We hold a working interest in seven disposal and seven injector wells, all of which are operated by third parties whose disposal practices are outside of our control.

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Potential environmental effects may also arise from the use of disposal and injector wells. We hold a working interest in seven disposal and seven injector wells, nine of which we operate, the remaining of which are owned and operated by third parties whose disposal practices are outside of our control.

Although environmental requirements do have a substantial impact upon the energy industry, these requirements do not appear to affect us any differently than other companies in this industry who operate in a given geographic area. We are not aware of any environmental claims which could have a material impact upon our financial condition, results of operations, or cash flows. Such regulations have increased the resources required and costs associated with planning, designing, drilling, operating and both installing and abandoning oil and natural gas wells and facilities. We maintain insurance coverage that we believe is customary in the industry.

Item 1A. Risk Factors

While we acknowledge that we have certain risk factors, “smaller reporting companies” are not required to provide information under this Item. Therefore, the absence of reporting under this Item should not be construed to indicate that we have no risk factors. Instead, we recognize that we have the same or similar risk factors as other comparable companies within our industry, especially companies with similar market capitalization and/or employee census.

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Item 1B. Unresolved Staff Comments.

Not Applicable.

Item 2. Properties

Executive Offices

We do not own any real property. We currently maintain our corporate office at 7065 Confederate Park Road, Suite 102, Fort Worth, Texas. We pay $1,300 per month, on a month to month basis.

Oil and Gas Properties

Producing Properties: Location and Impact

As of April 30, ~~2013~~2014, we owned ainterests ~~working interest~~ in 7564 gross producing wells in two states.

State and Well Information

Texas County	Producing Wells*		Net Well Count
Texas		7361.00		10.2564
Kansas		23.00		1.~~075~~05
Total*		7564.00		1.3069
*Does not include interests in saltwater disposal wells.

Production

Specific production data relative to our oil and natural gas producing properties can be found in the Results of Operations table in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Oil and Gas Reserves

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles, or GAAP, and Securities and Exchange Commission (“SEC”) guidelines. The accuracy of a reserve estimate is a function of:

•	the quality and quantity of available data;

•	the interpretation of that data;

•	the accuracy of various mandated economic assumptions;

•	the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the un-weighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. In prior years, such estimates had been based on year end prices and costs. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation, depletion and amortization expense. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

~~Proved Oil and Gas Reserves~~12

~~The~~Table ~~following table sets forth summary information regarding our estimated proved reserves, PV-10, and a reconciliation~~ of PV-10 to the Standard Measure as of April 30, 2013. See Note 12 to our consolidated financial statements in this report for additional information. Our reserve estimates and our calculation of Standard Measure and PV-10 are based on the 12-month average of the first day of the month pricing of $88.67 per Bbl of West Texas Intermediate posted oil price and $3.12 per MMBtu Henry Hub spot natural gas price from May 1, 2012 through April 1, 2013. Our estimated total proved reserves of oil and natural gas as of April 30, 2013 were 51,940 BOE, made up of 92% oil and 8% natural gas and natural gas liquids. The proved developed portion of total proved reserves at year end 2013 was 73%. Natural gas is converted at a rate of six Mcf of gas to one barrel of oil equivalent (“BOE”).Contents

	OIL (BBLS)		GAS (MCF)		BOE		Percent (%)			PV-10
Proved Developed		34,190		22,480		37,937		73		$	1,705,300
Proved Non Producing		5,360		1,570		5,622		11			278,440
Proved Undeveloped		8,030		2,110		8,382		16			355,940
Total Proved		47,580		26,160		51,940		100	%	$	2,339,680
Standardized measure of discounted future net cash flows										$	2,339,680

Estimated Proved Developed and Undeveloped Oil and Gas Reserves

The following table sets forth summary information regarding our estimated proved reserves, PV-10, and a reconciliation of PV-10 to the Standard Measure as of April 30, 2014. See Note 15 to our consolidated financial statements in this report for additional information. Our reserve estimates and our calculation of Standard Measure and PV-10 are based on the 12-month average of the first day of the month pricing of $98.68 per Bbl of West Texas Intermediate posted oil price and $4.03 per MMBtu Henry Hub spot natural gas price from May 1, 2013 through April 1, 2014. Our estimated total proved reserves of oil and natural gas as of April 30, 2014 were 69,710 BOE, made up of 92% oil and 8% natural gas and natural gas liquids. The proved developed portion of total proved reserves at year end 2014 was 50%. Natural gas is converted at a rate of six Mcf of gas to one barrel of oil equivalent (“BOE”).

The following table sets forth certain information regarding our estimated proved developed and proved undeveloped reserves of crude oil, natural gas liquids and natural gas as of April 30. 2014. All of our reserves are located in the United States.

	OIL (BBLS)		NGL (BBLS)		GAS (MCF)		BOE		Percent (%)			PV-10
Proved Developed		29,507		2,912		14,309		34,804		50	%	$	1,293,388
Proved Non-Producing		-		-		-		-		-	%		-
Proved Undeveloped		34,680		-		1,355		34,906		50	%	$	340,188

Total Proved		64,187		2,912		15,664		69,710		100	%	$	1,633,576

Standardized measure of discounted future net cash flows												$	1,633,576

Estimated Proved Undeveloped Crude Oil and Natural Gas Reserves

During 2014, we had a positive revision of 26,924 BOE, or 337%, of our April 30, 2013 estimated proved undeveloped reserves balance. The primary cause for these revisions was the addition of wells in our April 30, 2014 reserve report that had not been included in our April 30, 2013 reserve report. In addition to the underperformance of wells within our areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in our April 30, 2013 reserve report. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in our April 30, 2014 reserve report. A reconciliation of the change in proved undeveloped reserves during the year ended April 30, 2014 is as follows:

	BOE
Estimated Proved Undeveloped Reserves, beginning of year		7,982
PUD converted to PDP		-
PUD added during the year		33,048
Revisions of previous estimates		(6,124	)
Estimated Proved Undeveloped Reserves, end of year		34,906

PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP.

We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.

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Preparation of Proved Reserves Estimates

Internal Controls Over Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance. All of our reported oil and natural gas reserves have been estimated as of April 30, ~~2013~~2014, by the LaRoche Petroleum Consultants, Ltd. (“LRPC”) of Richardson, Texas. As of April 30, ~~2013~~2014, LRPC estimated reserves for all properties owned by the Company, which were located in Texas and Kansas, comprising 100% of the PV-10 of our oil and gas reserves as of that date. LRPC is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over thirty years. The average experience level of the staff at LPRC exceeds 35 years with major and independent oil company backgrounds. LRPC is employee-owned and maintains offices in Richardson, Texas. The office of LRPC that prepared our reserves estimates is registered in the state of Texas (License # 45012). LRPC prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells. Additionally, authorizations for expenditure ("AFEs"), geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to such engineer for consideration in estimating our underground accumulations of crude oil and natural gas. This information was reviewed by S. Jeffrey Johnson, our President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to LRPC. Mr. Johnson has worked in the oil and gas industry for over 25 years and has been a chief executive of a public oil and gas company for over nine years.

The report of LRPC dated ~~August~~July 79, ~~2013~~2014, which contains further discussions of the reserve estimates and evaluations prepared by LRPC as well as the qualifications of LRPC’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1.

Technologies Used in Preparation of Proved Reserves Estimates

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods used are limited to decline curve analysis which utilized extrapolations of historical production and pressure data available through April 30, ~~2013~~2014. The data used in this analysis was obtained from public data sources and was considered sufficient for calculating producing reserves. The proved undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through April 30, ~~2013~~2014.

Oil and gas reserves and the estimates of the present value of future net revenues were determined based on prices and costs as prescribed by SEC and Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated in accordance with guidelines established by the SEC and FASB, which require that reserves estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.

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Oil and Gas Production, Production Prices and Production Costs

The following table sets forth summary information regarding oil gas production, average sales prices and average production costs for ~~2013~~2014 and ~~2012~~2013. We determined the BOE using the ratio of six Mcf of natural gas to one BOE. The ratios of six Mcf of natural gas to one BOE does not assume price equivalency and, given price differentials, the price for a BOE for natural gas may differ significantly from the price for a barrel of oil.

	Year Ended April 30,
	2013		2012
	2014		2013
Production
Oil (Bbls)		79,~~469~~563		97,~~792~~469
Gas (Mcf)		813,~~995~~070		518,~~036~~995
Total (BOE)		811,~~968~~741		188,~~298~~968
Total (BOE/d)		2532		5025
Average prices
Oil (per Bbl)	$	~~102~~92.5076	$	77102.4950
Gas (per Mcf)		5.2545		35.5925
Total (per BOE)	$	9081.6362	$	5190.4963
Production Costs per BOE	$	89.0691	$	48.4106

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Drilling Activity

The following table sets forth information on our drilling activity for the ~~last~~fiscal ~~year~~years ended April 30, 2014, 2013 and 2012. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the numbers of productive wells drilled, quantities of reserves found or economic value.

	Gross		Net
	2014				2013				2012
Exploratory Wells:
	Gross		Net		Gross		Net		Gross		Net
Productive		3.0		0.48
Exploratory Wells
Dry		-		-
Productive		2.0		0.57		3.0		0.48		21.00		0.19
Total		3.0		0.48
Dry		-		-		-		-		1.0		0.01
Total		2.0		.57		3.0		0.48		22.0		0.20

Of the 32 gross (0.4857 net) wells drilled in ~~2013~~2014, all were completed as of April 30, ~~2013~~2014.

Although a well may be classified as productive upon completion, future changes in oil and gas prices, operating costs and production may result in the well becoming uneconomical.

Drilling Activity — Current

As of the date of this report, ~~two~~we ~~wells~~have ~~are~~recently ~~currently~~completed ~~being~~the ~~drilled~~drilling byof ~~Woodbine~~a ~~Acquisitions. As~~well ain ~~non-operator,~~Trego County Kansas in which we ~~are~~have ~~unaware~~a of60% ~~drilling~~net ~~activity~~working ~~until~~interest. This wewell ~~receive~~is ancurrently ~~AFE~~producing and online.

Delivery Commitments

We are not committed to provide a fixed and determinable quantity of oil, NGLs, or gas in the near future under existing agreements.

Producing Wells

The following table sets forth the number of producing wells in which we owned a either royalty or working interest at April 30, ~~2013~~2014. Wells are classified as natural gas or oil according to their predominant production stream.

	Gross		Net
Oil		6964.00		1.2569
Gas		60.00		0.7500
Total		7564.00		1.3069

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Acreage

The following table summarizes our developed and undeveloped acreage as of April 30, ~~2013~~2014.

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

Texas

24,962

275

19,026

155

43,988

430

Kansas

~~160~~320

40320

135,~~958~~800

146,~~118~~120

136,~~998~~120

Total

25,~~122~~282

~~315~~595

3224,~~984~~826

145,~~113~~955

5850,~~106~~108

146,~~428~~550

Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of crude oil and natural gas.

Leasehold Acreage Expirations

A significant portion of our acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related properties. As of April 30, 2014, we estimate that we had leases that were not developed that represented 4,680 net acres potentially expiring as follows:

	April 30,
	(in net acres)
Future expirations of net acreage
2015		4,680
2016		-
2017		-
2018		-
2019		-
Thereafter
Total		4,680

Item 3. Legal Proceedings.

Other than as listed below, we know of no material, active, or pending legal proceeding against the Company, nor are we involved as a plaintiff in any material proceeding or pending litigation where such claim or action involves damages for more than 10% of our current assets. There are no proceedings in which any of our company’s directors, officers, or affiliates, or any registered or beneficial shareholders, is an adverse party or has a material interest adverse to our ~~company~~Company’s interest.

~~Landers~~Convertible Notes

On ~~June~~October 1628, ~~2011~~2013, ~~Circle~~the ~~Star~~holders ~~acquired all~~ of ~~the~~our ~~outstanding~~10% ~~equity~~convertible ~~interest~~notes indue ~~JHE.~~February ~~JHE~~8, ~~was~~2013 ~~party to a litigation related to a mineral interest~~ in the ~~well~~principal ~~known~~amount asof ~~Landers~~$2,750,000 #1filed ~~(“Landers~~a ~~#1”)~~legal ~~that~~action ~~was~~against ~~initiated~~the inCompany ~~November 2008~~ in the District Court ~~82nd~~for ~~Judicial~~Clark ~~District~~County, ~~Robertson County~~Nevada, ~~Texas.~~in ~~The~~an ~~litigation~~attempt ~~involved a multi-party trespass~~ to ~~try~~collect ~~title suit to determine~~ the ~~ownership~~outstanding ofbalance ~~Landers~~related ~~#1.~~to ~~Ross~~these Lnotes. ~~Martella~~On ~~III~~February ~~originally~~28, ~~sought a temporary restraining order~~2014, ~~but~~ the ~~lawsuit~~Company ~~evolved~~entered into a ~~trespass~~settlement toagreement ~~try~~and ~~title~~new ~~action~~note ~~under~~agreements ~~Chapter~~with ~~22 of~~ the ~~Texas~~holders. ~~Property~~The ~~Code.~~amended Aand ~~Final~~restated ~~Judgment~~note ~~was~~agreements, ~~rendered~~each in the ~~suit~~amount inof ~~November 2010~~$1,155,000, ~~and~~accrue itinterest ~~became~~at ~~final~~12% per annum and ~~non-appealable~~mature inon December ~~2010. Subsequently~~31, ~~two additional litigation matters involving Landers #1 were initiated~~2014. The AsCompany ofalso ~~June~~issued 105, ~~2011~~000,000 ~~one~~shares of ~~the~~its ~~suits~~common ~~was~~stock ~~dismissed,~~ and ~~Orbis~~warrants ~~has agreed~~ to ~~indemnify~~purchase ~~JHE~~an inaggregate ~~connection~~of ~~with the remaining litigation related to Landers #1. In December 2012~~5,000,000 ashares ~~dismissal without prejudice judgment related~~ to the ~~Landers #1 litigation was executed~~holders.

~~Cottonwood~~Jonathan G. Pina

On orJanuary ~~about~~27, ~~June~~2014 ~~18,~~Jonathan ~~2012~~Pina, ~~the~~our ~~Company’s~~former ~~registered~~Chief ~~agent~~Financial ~~was~~Officer, ~~served~~filed ~~with~~ a ~~complaint~~legal ~~(Civil~~action ~~Action~~against ~~No.~~the ~~12-CV-327-CVE-PJC)~~Company ~~filed~~ in the ~~United States~~ District Court ~~for the Northern District~~ of ~~Oklahoma~~Harris byCounty ~~Cottonwood Natural Resources~~Texas, ~~Ltd. (“Cottonwood”). Cottonwood alleges breach of contract and fraud~~ in ~~connection~~an ~~with~~attempt ~~a Purchase and Sale Agreement dated April 19, 2012 between the Company and Cottonwood (the “Cottonwood Purchase Agreement”) related~~ to ~~the~~collect ~~purchase~~vacation ofpay ~~certain oil~~ and ~~gas~~for ~~interests~~alleged infailure approximately 14,640 acres in Finney County, Kansas (the “Finney Property”). Cottonwood filed the complaint after the Company terminated the Cottonwood Purchase Agreement after the Company determined that Cottonwood had options to ~~title~~pay toseverance ~~less than 12,908.46 net acres,~~ and ~~Cottonwood~~benefits ~~failed~~for toresignation ~~disclose~~with ~~all~~good ~~material facts related to the Finney Property~~reason. ~~Cottonwood~~The ~~was seeking damages of at least $4,324,180. On May 31, 2013 a mutual release and settlement agreement was executed by all parties. In connection therewith, the~~ Company ~~assigned~~intends ~~4,160 acres in Sheridan County, Kansas~~ to ~~Cottonwood~~defend onthis ~~June~~legal 5,action ~~2013~~vigorously.

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Greene Litigation

On March 6, 2012, the Company entered into an agreement (the “Greene Agreement”) to purchase certain interests in 6,518 acres of land in Kansas for a total purchase price of $9,125,200. Pursuant to the Greene Agreement, Circle Star delivered a non-refundable $50,000 deposit to the sellers. The deposit was to be applied to the purchase price upon closing.

On June 19, 2012, the Company filed a petition with the District Court of Clark County, Kansas, Sixteenth Judicial District (Case No. 2012-CV-12) against Greene Brothers Land Company, LLC, Greene Ranch Enterprises, Inc., David M. Greene, Jr., Marcia Greene, Thomas E. Greene, Janice C. Greene, Joseph B. Greene and Billie Greene (collectively the “Defendants”), requesting the return of the deposit, pursuant to the termination of the Greene Agreement. Circle Star terminated the Greene Agreement as a result of defects in title which the Defendants did not cure within the time period set forth in the Greene Agreement. On November 13, 2012 the Company entered into a settlement agreement whereby the pending Greene litigation was settled. The settlement agreement stipulated that Circle Star was to receive $32,500 of the initial deposit from the sellers net of legal fees. The execution of the settlement agreement constitutes a termination of the litigation. The remaining balance of the deposit $17,500 has been charged to impairment expense as of April 30, 2013. On December 11, 2012 we received $22,922 in cash net of legal fees of $9,578 related to the settlement of this matter.

Item 4. Mine Safety Disclosures.

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company is traded on the OTCBB under the ticker symbol “CRCL.” The Company had previously been trading under the symbol “DTLV” but changed its ticker symbol to “CRCL” effective July 1, 2011.

PERIOD	LOW ($)		HIGH ($)
First Quarter 2011		0.005		0.005
Second Quarter 2011		0.005		0.10
Third Quarter 2011		0.10		0.13
Fourth Quarter 2011		0.13		0.50
First Quarter 2012		0.50		2.25
Second Quarter 2012		1.87		2.00
Third Quarter 2012		1.87		2.15
Fourth Quarter 2012		2.00		2.75
First Quarter 2013		0.46		2.38
Second Quarter 2013		0.15		0.65
Third Quarter 2013		0.18		0.48
Fourth Quarter 2013		0.07		0.36
First Quarter 2014		0.02		0.12
Second Quarter 2014		0.03		0.05
Third Quarter 2014		0.01		0.04
Fourth Quarter 2014		0.01		0.04

The closing price per share for our common stock on August 97, ~~2013~~2014, as reported by the OTCBB was $0.0301.

Holders of our Common Stock

On August 137, ~~2013~~2014, the shareholders’ list of our common stock had 6870 registered shareholders and 5072,~~137~~718,~~916~~044 shares outstanding.

Dividend Policy

We have not paid any cash dividends on our common stock and have no present intention of paying any dividends on the shares of our common stock. Our future dividend policy will be determined from time to time by our Board.

Securities Authorized for Issuance Under Equity Compensation Plan

On July 6, 2011, the Company’s Board of Directors adopted the 2011 Stock Option Plan. The Plan is subject to ratification by shareholders at the Company’s next annual meeting for the purpose of qualifying the issuance as incentive stock options.

Pursuant to the Plan, options to purchase shares of common stock and/or stock grants of the Company's stock may be granted to any person who is performing or who has been engaged to perform services of special importance to management of the Company in the operation, development and growth of the Company. The maximum number of shares with respect to which stock options and/or grants may be granted under the Plan may not exceed 3,000,000 shares of common stock of the Company. The Plan permits the Company to grant both incentive and non-incentive stock options and requires each such grant to be evidenced by a stock option agreement, which shall be subject to the applicable provisions of the Plan.

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The following table sets forth information regarding our equity compensation plans as of April 30, ~~2013~~2014.

Plan category

Number of securities to be issued upon exercise of outstanding options warrants and rights

Weighted-average exercise price of outstanding options, warrants and rights

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

(a)

(b)

(c)

Equity compensation plans approved by security holders

Equity compensation plans not approved by security holders

~~350,000~~-

~~0.50~~-

23,~~650~~000,000

Total

~~350,000~~-

23,~~650~~000,000

OnRecent ~~July~~Sales ~~11, 2011, the Company granted 350,000 stock options granted to G. Jonathan Pina, the former Chief Financial Officer~~ of ~~the~~Unregistered ~~Company, which vested over a three-year period. Mr. Pina’s options were forfeited on July 23, 2013, 90 days after his resignation from the company~~Securities

In February and March 2014, we issued 2,400,000, 1,600,000, and 1,526,582 shares of common stock at conversion rates of $0.06, $0.059 and $0.059 per share, respectively, in connection with the conversion of convertible notes.

In March 2014, we issued 5,000,000 shares of common stock to holders of our February 8, 2013, 10% convertible notes at $0.0145 per share in connection with the amendment and restatement of the underlying note agreements.

In March 2014, we issued 7,758,621 shares of common stock at $0.0145 per share as bonuses to our Chief Executive Officer and an employee of the Company. In addition we issued 3,103,448 shares of common stock at $0.0145 to an employee of the Company in connection with the satisfaction of accrued salaries payable.

In April 2014, we issued a total of 283,333 shares of common stock to employees of the Company, which represented the completion of the requisite vesting period. The shares were initially granted at $2.60 per share.

No underwriters were used in the above stock transaction. We relied upon the exemption from registration contained in Section 4(2) of the Securities Act of 1933, as the investor was deemed to be sophisticated with respect to the investment in the securities due to his financial condition and involvement in our business. A restrictive legend was placed on the certificates evidencing the securities issued.

Item 6. Selected Financial Data.

As a “smaller reporting company,” we are not required to provide this information.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

The following discussion should be read in conjunction with our audited financial statements and the related notes that appear elsewhere in this annual report. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward looking statements. Factors that could cause or contribute to such differences include those discussed below and elsewhere in this annual report.

Our consolidated financial statements are stated in United States dollars and are prepared in accordance with United States generally accepted accounting principles.

Critical Accounting Policies and Estimates

See Note 3 to the consolidated financial statements.

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Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company iswas required to implement this guidance effective for the first quarter of fiscal 2014 ~~and does not expect~~ the adoption of ASU 2011-11 todid not have a material impact on ~~its~~our consolidated financial statements.

Various other accounting pronouncements have been recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to have a material effect on our financial position, results of operations, or cash flows.

Off Balance Sheet Arrangements

We have no significant off balance sheet transactions, arrangements or obligations.

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Results of Operations

The following table sets forth summary information regarding oil and gas revenues, production, average product prices and average production costs and expenses for the fiscal years ended April 30, ~~2013~~2014 and April 30, ~~2012~~2013, respectively. We had no crude oil and natural gas operations prior to the fiscal year beginning May 1, ~~2012~~2011. We determined the BOE using the ratio of six Mcf of natural gas to one BOE. The ~~ratios~~ratio of six Mcf of natural gas to one BOE dodoes not assume price equivalency and, given price differentials, the price for a BOE for natural gas or NGLs may differ significantly from the price for a barrel of oil.

	Year Ended April 30,
	2013		2012
	2014		2013
Revenues
Oil	$	~~765~~887,~~548~~087	$	~~758~~765,~~798~~548
Gas		47,214		183,352
Gas (1)		71,255		47,214
Total oil and gas sales	$	~~812~~958,~~762~~342	$	~~942~~812,~~150~~762
Production
Oil (Bbls)		79,~~469~~563		97,~~792~~469
Gas (Mcf)		813,~~995~~070		518,~~036~~995
Total (BOE)		811,~~968~~741		188,~~298~~968
Total (BOE/d)		2532		5025
Average prices
Oil (per Bbl)	$	~~102~~92.5076	$	77102.4950
Gas (per Mcf)		5.2545		35.5925
Total (per BOE)	$	9081.6362	$	5190.4963
Costs and expenses (per BOE)
Lease operating (1)	$	8.06	$	4.41
Lease operating (2)	$	9.91	$	8.06
Severance and production taxes		54.09		25.7509
Exploration		~~8.99~~-		58.0499
Impairment		~~530.~~64.40		~~211~~530.0164
General and administrative		~~470~~127.5032		~~316~~470.7950
Depreciation, depletion, and amortization		4446.1965		3144.4819

(1) ~~Includes~~ adAmount ~~valorem~~includes ~~taxes~~NGL revenue. For the years ended April 30, 2014 and 2013, the NGL revenue included in the natural gas revenue amounts are $56,737 and $26,575 respectively.

(2)	Includes ad valorem taxes.

Oil and Gas Sales

Oil and gas sales were $~~812~~958,~~762~~342 for the fiscal year ended April 30, ~~2013~~2014, compared to $~~942~~812,~~150~~762 for the fiscal year ended April 30, ~~2012~~2013. The ~~decrease~~increase in sales ~~was~~of ~~attributable~~approximately to18% ~~decreased~~was ~~production~~attributable ~~related~~primarily to ~~natural decline curves in our wells and~~ the ~~disposition~~addition of ~~Encana~~two ~~assets~~wells, ~~(primarily gas)~~ offset by ~~increases~~our inconveyance ~~realized~~of ~~prices~~certain royalty interests. In the fiscal year ended April 30, ~~2013~~2014, the average price we received for our production was $9081.6362 per BOE, compared to $5190.4963 per BOE for the fiscal year ended April 30, ~~2012~~2013. We The ~~believe~~decrease ~~that~~in ~~revenues~~average ~~should~~price ~~increase~~per ~~during~~BOE was due to the ~~fiscal~~impact ~~year~~of ~~ending~~payments ~~April~~made 30to an unrelated third party for Net Profits Interest. Excluding the effect of the Net Profits Interest adjustment, ~~2014~~the asaverage price we ~~implement~~received for our ~~operating~~production ~~plan~~was $90.44 per BOE in 2014.

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Net Loss

Net loss for the fiscal year ended April 30, ~~2013~~2014 was $101,~~812~~030,~~694,~~129 or $(0.2702) per basic and diluted share, compared to a net loss of $1110,~~078~~812,~~248~~694, or $(0.3427) per basic and diluted share for the fiscal year ended April 30, ~~2012~~2013. ~~Net~~We ~~loss~~generated ~~per~~a ~~basic~~net ~~and~~loss ~~diluted~~for ~~share decreased in~~ the fiscal year ended April 30, ~~2013~~2014 ~~over~~as ~~the~~a ~~fiscal~~result ~~year~~of ~~ended~~higher ~~April 30~~depletion, ~~2012~~offset ~~primarily~~by ~~due to~~ lower ~~total~~ general and administrative expenses, ~~resulting~~lower ~~from~~impairment ~~our~~expenses ~~cost~~and ~~cutting~~a ~~efforts~~gain infrom the ~~fourth~~conveyance ~~quarter~~ of ~~2013,~~certain ~~offset~~oil byand ~~impairment~~gas ~~charges~~properties. We believe that we ~~will~~may ~~continue to~~ incur a net ~~losses~~loss ~~during~~for the fiscal year ending April 30, ~~2014, although they will decrease as we have already taken significant impairment charges~~2015.

~~Oil and Gas Production~~18

~~Production~~Table for the fiscal year ended April 30, 2013 totaled 8,968 BOE (25 BOE/d), compared to 18,298 BOE (50 BOE/d) for the fiscal year ended April 30, 2012. Production for the fiscal year ended April 30, 2013 was 83% oil and 17% natural gas, as compared to 54% oil and 46% natural gas for the fiscal year ended April 30, 2012. The decrease in production in the fiscal year ended April 30, 2013 is primarily the result of the disposition of the Encana assets and the natural decline curves in our wells which were partially offset by new production coming online. We believe that production may increase during the fiscal year ending April 30, 2014 as we begin to implement our operating plan.Contents

Crude Oil and Natural Gas Production

Production for the fiscal year ended April 30, 2014, totaled 11,741 BOE (32 BOE/d), compared to 8,968 BOE (25 BOE/d) for the fiscal year ended April 30, 2013, an increase of 31%. Production for the fiscal year ended April 30, 2014, was 81% crude oil and 19% natural gas and natural gas liquids, as compared to 83% crude oil and 17% natural gas and natural gas liquids for the fiscal year ended April 30, 2013. The increase in production in the fiscal year ended April 30, 2014, is primarily the result of the addition of two wells offset slightly by the natural decline curves in our wells and our conveyance of certain royalty interests.

Lease Operating Expense

Our lease operating expenses (“LOE”) were $72116,~~248~~347 for the fiscal year ended April 30, ~~2013~~2014, compared to $8072,~~723~~248 for the fiscal year ended April 30, ~~2012~~2013, an increase of 61%. The ~~decrease~~increase in LOE for the fiscal year ended April 30, ~~2013~~2014 was attributable primarily to ~~the disposition~~increased ofoil ~~the~~volume ~~Encana~~produced ~~assets~~coupled with non-recurring one time charges.

The following table summarizes LOE per BOE for the years ended April 30, ~~2013~~2014 and April 30, ~~2012~~2013, respectively.:

	Year Ended April 30,
	2013		2012
	2014		2013
Non-op LOE	$	7.22	$	3.59
Lease operating expense	$	6.96	$	7.22
Ad valorem taxes		02.8495		0.8384
Total	$	89.0691	$	48.4206

Severance and Production Taxes

Our severance and production taxes for the fiscal year ended April 30, ~~2013~~2014 were $4548,~~668~~041 or 54.65% of revenues, compared to $5045,~~334~~668 or 5.36% of revenues for the fiscal year ended April 30, ~~2012~~2013. The ~~decrease~~increase in severance and production taxes was primarily due to ~~the~~increased ~~sale of the Encana assets. We believe that~~ production ~~and severance taxes may increase during the fiscal year ending April 30, 2014 as a result of the implementation of our operating plan~~volumes.

Exploration Expense

We recorded $~~80,579~~nil of exploration expense for the fiscal year ended April 30, ~~2013~~2014, compared to $9280,~~247~~579 for the fiscal year ended April 30, ~~2012~~2013. Exploration expense for the fiscal year ended April 30, 2013 was primarily related to geological and geophysical services incurred for the acquisition of leases in Kansas. ~~We believe that exploration expenses may increase during the fiscal year ending April 30, 2014 as we implement our operating plan.~~

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Impairment

We review our long-lived assets, including proved and unproved crude oil and natural gas properties accounted for under the successful efforts method of accounting. For the fiscal year ended April 30, ~~2013~~2014, our total impairment expense was $4756,~~758~~167,~~812,~~ compared to $34,~~861~~758,~~083~~812 for the fiscal year ended April 30, ~~2012~~2013. InThe ~~2013, included in~~ impairment expense ~~was~~in ~~approximately~~2014 included $3708,~~500,000~~015 ~~related~~impairment ~~to the forfeiture~~ of ~~non-refundable~~our ~~lease~~unproved ~~deposits,~~oil ~~approximately~~and ~~$950,000~~gas properties related to ~~acreage~~expiring ~~transferred~~leased acreage in ~~connection~~Sheridan ~~with~~County, ~~the settlement of litigation~~Kansas, and ~~approximately,~~ $~~250~~48,~~000~~152 ~~recorded~~impairment inof ~~connection~~our ~~with~~proved ~~expiring~~oil ~~leased~~and ~~acreage.~~gas Inproperties ~~2012, $3,397,693 was~~ related to ~~the~~capitalized ~~acquisition~~costs in excess of ~~JHE~~future ~~and~~anticipated ~~based~~cash onflow ~~the~~from ~~fair~~reserves. In ~~value~~2013, ofincluded ~~assets~~in ~~acquired~~impairment ~~and the~~expense ~~remaining~~was approximately $~~463~~3,~~390~~500,000 related to the ~~acquisition~~forfeiture of ~~the~~non-refundable ~~Redfish~~lease ~~Properties~~deposits, ~~and~~approximately ~~was~~$950,000 arelated ~~result~~to ofacreage ~~the~~transferred ~~evaluation~~in ofconnection ~~carrying~~with ~~value~~the settlement of ~~oil~~litigation, and ~~gas~~approximately ~~properties~~$250,000 atrecorded ~~year-end. We~~in doconnection ~~not~~with ~~believe~~expiring ~~that~~leased ~~our~~acreage. We ~~assets~~may ~~will~~ be subject to further impairment during the fiscal year ending April 30, ~~2014 due to the expected future increase in both oil and gas prices~~2015.

General and Administrative Expenses

Our general and administrative expenses (“G&A”) decreased to $41,~~219~~494,~~407~~869 or 65%, in the fiscal year ended April 30, ~~2013~~2014 from $54,~~796~~219,~~640~~407 in the fiscal year ended April 30, ~~2012~~2013. Of the $41,~~291~~494,~~407~~869 in G&A costs for fiscal year ended ~~2013~~2014, $2553,~~289,537~~160 was non-cash related compared to $42,~~099~~289,~~558~~537 in non-cash related expenses in the fiscal year ended ~~2012~~2013. The decrease in G&A is primarily due to reduction in share based compensation and reduced professional fees~~. We~~ ~~expect~~and ~~G&A~~reduced ~~expenses~~salaries toand ~~decrease during the fiscal year ending April 30, 2014 as we continue to implement cost cutting initiatives~~benefits.

The following table summarizes G&A.:

	Year Ended April 30,
	2013		2012
	2014		2013
Share-based compensation	$	2553,~~289,537~~160	$	42,~~099~~289,~~558~~537
Professional fees		~~894~~315,~~423~~944		1894,~~018,357~~423
Salaries and benefits		~~643~~502,~~667~~114		~~377~~643,~~348~~667
Other		~~391~~123,~~780~~651		~~301~~391,~~377~~780
Total	$	41,~~219~~494,~~407~~869	$	54,~~796~~219,~~640~~407

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Depreciation, Depletion and Amortization Expense

Our depreciation, depletion and amortization expense (“DD&A”) was $~~396~~547,~~319~~704 in the fiscal year ended April 30, ~~2013~~2014 and $~~575~~396,~~990~~319 in the fiscal year ended April 30, ~~2012~~2013. The ~~decrease~~increase in DD&A is attributable primarily to aan ~~decrease~~increase in production, partially offset by increase in estimated proved reserves primarily related to the addition of two wells. Production on a BOE equivalent basis was 811,~~968~~741 during the year ended April 30, ~~2013~~2014, acompared ~~decrease~~to 8,968, an increase of 92,~~330~~773 or 5131% on a BOE basis when compared to the fiscal year ended April 30, ~~2012~~2013.

Interest Expense, net

Our interest expense, net, was $1727,~~556,881~~011 for the fiscal year ended April 30, ~~2013~~2014 and $1,~~693~~556,~~084~~881 for the fiscal year ended April 30, ~~2012~~2013. This decrease was the result of lower average notes payable balance outstanding during the year ended April 30, ~~2013~~2014 coupled with a decrease in one time charges to interest expense incurred in connection with conversion and modification of notes payable in the prior period.

Equity (Losses) in Earnings of Unconsolidated Affiliates

Our income related to the results of operations of unconsolidated affiliates were $27,250 for the fiscal year ended April 30, 2014, as compared to a loss of $(11,671) for the year ended April 30, 2013. The income relates to our reclassification of amounts paid related to a Net Profits Interest in the amount of $101,354 as a component of crude oil and natural gas revenue whereas corresponding amounts for the prior period had been included as components of losses incurred in connection with our equity method investment.

Gains (Losses) in Connection with Conversion and Settlement of Debt and Accrued Liabilities

Gains recorded during the fiscal year ended April 30, 2014 related to debt conversions and the settlement of accrued liabilities amounted to $413,206, as compared to a loss of $(465,046) partially offset by a gain on forgiveness of debt and accrued liabilities of $48,280 during the year ended April 30. 2013. The change relates to gains on settlement of accounts payable and accrued salaries in 2014 versus losses related to convertible debt conversions in 2013.

Gains (Losses) in Connection with the Sale of Assets

Gains recorded in connection with the conveyance of interests in oil and gas properties amounted to $1,232,279 for the fiscal year ended April 30, 2014 as compared to losses of $(89,847) during the fiscal year ended April 30, 2013. On January 24, 2014, the Company completed the assignment of certain royalty and over-riding royalty interests related to 14 wells located in Madison, Grimes, Dimmit and Fayette counties in Texas to unrelated third parties. Net capitalized costs associated with the interests conveyed amounted to $665,165. Net cash consideration received in connection with the conveyance amounted to $1,897,444. In connection with the conveyance we have recorded a gain of $1,232,279.

Purchase or Sale of Equipment

To date there have not been any purchases or sales of equipment except as associated with our acquisitions and / or development of oil and gas properties. We may acquire other equipment in connection with our oil and gas business.

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Liquidity and Capital Resources

We generally rely on cash generated from operations and, to the extent that credit and capital market conditions will allow, future equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings will be available on acceptable terms, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices, production volumes and the effect of commodity derivatives – if we choose to purchase any such derivatives. Prices for oil and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties and corporate general and administrative expenses.

Recognizing we do not have adequate liquidity from cash generated from operations for current working capital needs and maintenance of our current drilling and acquisition program, we will need to access the public or private equity or debt markets for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all.

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Going Concern Consideration

Our auditors included an explanatory paragraph in their report on the accompanying financial statements regarding concerns about our ability to continue as a going concern. Our financial statements contain additional note disclosures describing the circumstances that lead to this disclosure by our registered independent auditors.

Due to this doubt about our ability to continue as a going concern, management ~~was~~is open to new business opportunities which may prove more profitable to the shareholders of the Company. Historically, we have been able to raise a limited amount of capital through private placements of debt and equity. However, we are uncertain about our continued ability to raise funds privately. If we are unable to secure adequate capital to continue operations, our business may fail and our stockholders may lose some or all of their investment.

Liquidity

We define liquidity as year-end net cash and cash equivalents. We had $~~125~~395,~~109~~735 and $60125,~~626~~109 of liquidity at April 30, ~~2013~~2014 and ~~2012~~April 30, 2013, respectively.

Working Capital

Our working capital is affected primarily by our cash and cash equivalents balance, short term debt obligations, and our capital spending program. At April 30, ~~2013~~2014, we had a working capital deficit of $43,~~167~~648,~~097~~330, compared to a working capital deficit of $34,~~163~~167,~~141~~097 at April 30, ~~2012~~2013. The ~~change~~decrease in working capital deficit for the fiscal year ended April 30, ~~2013~~2014, is primarily attributable to our gain on sale of oil and gas assets, offset by capital expended on G&A, drilling, operations, and acquisition support.

Cash Flows

The following table summarizes our sources and uses of funds for the periods noted.:

	2013			2012
	2014			2013
Cash flows used in operating activities	$	(1897,~~359,795~~643	)	$	(~~625~~1,~~707~~359,795	)
Cash flows provided by (used in) investing activities		611,724			(1,757,928	)
Cash flows provided by investing activities		1,633,269			611,724
Cash flows provided by financing activities		812,554			2,437,565
Cash flows provided by (used in) financing activities		(465,000	)		812,554
Net increase in cash and cash equivalents	$	64270,~~483~~626		$	5364,~~930~~483

For fiscal years ended April 30, ~~2013~~2014 and April 30, ~~2012~~2013, our primary sources of cash were from the sale of crude oil and natural gas. Sales of crude oil and gas properties, financing activities and proceeds related to advances received from our working interest partners. In ~~2013~~2014 net cash received of $~~812~~1,~~554~~633,269 was primarily comprised of ~~advances~~proceeds from ~~our~~the ~~working~~sale ~~interest~~of ~~partners~~oil and gas properties. In ~~2012~~2013, net cash received from financing activities was $2812,~~437,565~~554. Proceeds were used to fund operations, drilling activity and debt repayment during the fiscal years ended April 30, ~~2013~~2014 and ~~2012~~2013, respectively.

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Operating Activities

For the fiscal year ended April 30, ~~2013~~2014, cash flows used in operating activities ~~increased~~decreased by $~~734~~462,~~088~~152 to $1897,~~359,795~~643 from cash flows used in operating activities of $~~625~~1,~~707~~359,795 in the fiscal year ended April 30, ~~2012~~2013, primarily due to andecreases ~~increase~~ in G&A expenses, excluding the impact of share-based compensation, impairment expense, amortization of debt discount associated with our convertible notes payable, and other non-cash adjustments.

Investing Activities

Cash ~~from~~provided by investing activities was $~~611~~1,~~724~~633,269 during the fiscal year ended April 30, ~~2013~~2014 as compared to ~~cash used in investing activities of~~ $1611,~~757,928~~724 for the fiscal year ended April 30, ~~2012,~~2013. The increase in cash provided by investing activities during ~~2013~~2014, relates primarily to ~~increased~~proceeds from the sale of oil and gas properties, offset by lower amounts received from our working interest partners ~~during the~~and ~~fiscal~~higher ~~year,~~distributions ~~coupled~~in connection with ~~significant~~working ~~decreases~~interest inpartners ~~acquisition~~during the ~~costs~~fiscal year. The majority of our cash flows used in investing activities for the fiscal years ended April 30, ~~2013~~2014 and April 30, ~~2012~~2013 have been used for drilling and acquisitions in Texas and Kansas.

~~The following table is a summary of capital expenditures related to our oil and gas properties.~~21

	Year Ended April 30,
	2013			2012
JHE Holdings	$	-		$	(1,000,000	)
Redfish Prospect		-			(193,717	)
Leasehold		(223,945	)		(334,328	)
Proceeds received from working interest partners		1,239,629			-
Cash from investment		12,535			5,449
Distributions in connection with working interest partners		(416,495	)		-
Other		-			(225,332	)
Total	$	611,724		$	(1,757,928)

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The following table is a summary of capital expenditures related to our oil and gas properties:

	Year Ended April 30,
	2014			2013
Leasehold		(134,915	)		(223,945	)
Proceeds received from working interest partners		468,000			1,239,629
Cash from investment		-			12,535
Distributions in connection with working interest partners		(597,260	)		(416,495	)
Sale of oil and gas properties		1,897,444			-
Total	$	1,633,269		$	611,724

Financing Activities

For Fiscal 2014, financing activities used cash of $465,000, as compared $812,554 provided in Fiscal 2013. We received $150,~~950,~~000 from the issuance of ~~common~~convertible ~~stock~~notes and ~~the~~repaid ~~receipt~~a total of ~~cash~~$515,000 ~~related~~of tooutstanding ~~warrants~~notes ~~exercised~~in ~~during~~ the ~~prior~~ fiscal year ended April 30, ~~and~~2014. In comparison, we received $~~125~~750,000 from the issuance of ~~convertible~~common ~~notes. In Fiscal 2012~~stock, ~~we had borrowings of~~ $41,~~750~~200,000~~. We~~ ~~repaid~~from awarrant ~~total~~subscription ofproceeds, and $1125,~~250,~~000 offrom ~~outstanding~~the ~~notes~~issuance ~~fiscal~~of ~~year~~convertible ~~ended April 30~~notes, ~~2013,~~while asrepaying ~~compared to~~ $51,~~000~~250,000 of outstanding notes during the fiscal year ended April 30, ~~2012~~2013.

2014 Capital Expenditures

We caution that we cannot reasonably estimate what our expenditures for the coming fiscal year will be; however, we will attempt to participate in all activities which will allow us to maintain our current level of participation and ownership interests. We are continually evaluating drilling and acquisition opportunities to continue to grow our asset base with the goal to potentially increase our cash flows.

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General Trends and Outlook

Our financial results depend upon many factors, particularly our ability to raise capital and fund debt. The price of oil and gas also impacts our financial results. Commodity prices are affected by changes in market demand, which is impacted by domestic and foreign supply of oil and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other gas producing and oil producing countries, weather and technological advances affecting oil and gas consumption. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through the capital markets.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

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Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time to time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues and increase future expected costs necessary to develop existing reserves.

To fund our current working capital needs and maintain our current drilling and acquisition program, we must access the public or private equity or debt markets. Also, additional capital is necessary for future development of reserves, acquisitions, additional working capital or other liquidity needs. We cannot guarantee that such financing will be available on acceptable terms or at all.

Subsequent Events

OnThere ~~May~~were 1,no ~~2013,~~significant ~~Mr.~~subsequent ~~Johnson, our Chief Executive Officer, transferred his ownership of the net profits interest on JHE to an unrelated third party~~events.

On May 31, 2013, a mutual release and settlement agreement was executed between the Company and Cottonwood Natural Resources, Ltd. In connection therewith, the Company assigned 4,160 acres in Sheridan County, Kansas to Cottonwood on June 5, 2013. This mutual release indicates the end settlement of litigation between the two parties as described elsewhere herein.

On June 19, 2013, we borrowed $50,000 under the terms of our 10% September 14, 2014 convertible note payable agreement.

On various dates in May, June and July 2013, the holders of our 10%, September 14, 2014 notes converted $82,838 in principal into 2,296,748 shares of our common stock.

On or about July 1, 2013, we issued 3,917,764 shares of our common stock to officers and employees of the Company in connection with the extinguishment of accrued salaries and payroll related liabilities.

Off-Balance Sheet Arrangements

We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Not Applicable.

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Item 8. Financial Statements and Supplementary Data.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	3125
Report of Independent Registered Public Accounting Firm	32
Consolidated Balance Sheets as of April 30, 2014 and 2013	26
Consolidated Balance Sheets as of April 30, 2013 and 2012	33
Consolidated Statements of Operations for the Years Ended April 30, 2014 and 2013	27
Consolidated Statements of Operations for the Years Ended April 30, 2013 and 2012	34
Consolidated Statements of Changes in Stockholders’ Deficit for the Years Ended April 30, 2014 and 2013	28
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Years Ended April 30, 2013 and 2012	35
Consolidated Statements of Cash Flows for the Years Ended April 30, 2014 and 2013	29
Consolidated Statements of Cash Flows for the Years Ended April 30, 2013 and 2012	36
Notes to Consolidated Financial Statements	31
Notes to Consolidated Financial Statements	38

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Circle Star Energy Corp.

We have audited the accompanying consolidated balance ~~sheet~~sheets of Circle Star Energy Corp. and Subsidiaries. as of April 30, 2014 and 2013 and the related consolidated statements of operations, changes in stockholders’ ~~equity (~~deficit), and cash flows for the ~~year~~years ~~then~~ ended April 30, 2014 and 2013. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our ~~audit~~audits.

We conducted our ~~audit~~audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the ~~audit~~audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our ~~audit~~audits ~~provides~~provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Circle Star Energy Corp. as of April 30, 2014 and 2013 and the results of their operations and their cash flows for the ~~year~~years ~~then~~April ~~ended~~30, 2014 and 2013 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has ~~incurred~~ net losses and used cash in operating activities of $101,~~812~~030,~~694~~129 and $1897,~~359~~643,~~795,~~ respectively, for the year ended April 30, ~~2013~~2014, and the Company had an accumulated deficit and stockholders’ deficit of $2223,~~061~~091,~~177~~306 and $2,~~317~~301,~~347~~989, respectively, and a working capital deficit of $43,~~167~~648,~~097~~330 at April 30, ~~2013~~2014. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ D’Arelli Pruzansky, P.A.

Certified Public Accountants

Boca Raton, Florida

~~August~~July 831, ~~2013~~2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Circle Star Energy Corporation

We have audited the accompanying consolidated balance sheet of Circle Star Energy Corporation and subsidiaries (collectively, the “Company”) as of April 30, 2012, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Circle Star Energy Corporation and subsidiaries as of April 30, 2012, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Hein & Associates LLP

Dallas, Texas

August 13, 2012

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

April 30,

	2013			2012
	2014			2013
ASSETS
CURRENT ASSETS:
Cash	$	~~125~~395,~~109~~735		$	60125,~~626~~109
Trade accounts receivable		128,117			153,872
Receivables:
Warrant subscriptions receivable		-			1,200,000
Crude oil and natural gas		174,235			128,117
Prepaid expenses and other assets		42,840			13,972
Joint interest and other (net)		47,638			-
Total Current Assets		296,066			1,428,470
Prepaid expenses and other assets		17,283			42,840
Oil and gas properties at cost, using the successful efforts method, net		3,013,247			5,955,129
Total Current Assets		634,891			296,066
Oil and gas properties at cost, using the successful efforts method, net		1,185,969			3,013,247
OTHER ASSETS:
Investment in partnership		167,215			167,215
Furniture and fixtures, net		-			~~6,596~~-
Total Other Assets		167,215			~~173~~167,~~811~~215
Total Assets	$	31,~~476~~988,~~528~~075		$	73,~~557~~476,~~410~~528
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable	$	~~678~~135,~~292~~802		$	~~253~~678,~~759~~292
Accrued liabilities		~~334~~135,~~464~~355			6334,~~447~~464
Bank overdrafts		-			409,544
Salaries and taxes payable		1,212			197,046
Salaries and taxes payable		197,046			3,081
Interest payable		315,215			436,890
Due to related party		-			24,521
Derivative liabilities associated with convertible notes		-			63,671
Interest payable		436,890			86,472
Convertible notes payable, net of unamortized discount		3,695,637			2,752,800
Seller note payable		-			1,500,000
Total Current Liabilities		4,283,221			4,463,163
Derivative liabilities associated with convertible notes		63,671			-
Convertible notes payable, net of unamortized discount		-			1,330,712
Convertible notes payable, net of unamortized discount		2,752,800			2,307,787
Asset retirement obligation		6,843			-
Total Current Liabilities		4,463,163			4,591,611
Total Liabilities		4,290,064			5,793,875
Convertible notes payable, net of unamortized discount		1,330,712			1,207,379
STOCKHOLDERS’ DEFICIT
Total Liabilities		5,793,875			5,798,990
Common stock, 100,000,000, par value $0.001 shares authorized, 72,424,711 and 44,173,404 common shares issued and outstanding at April 30, 2014 and April 30, 2013, respectively.		72,424			44,174
STOCKHOLDERS’ EQUITY (DEFICIT)
Additional paid in capital		20,716,893			19,699,656
Common stock, 100,000,000, par value $0.001 shares authorized, 44,173,404 and 35,693,571 common shares issued and outstanding at April 30, 2013 and April 30, 2012, respectively.		44,174			35,694
Accumulated deficit		(23,091,306	)		(22,061,177	)
Additional paid in capital		19,699,656			12,971,209
Total Stockholders’ Deficit		(2,301,989	)		(2,317,347	)
Accumulated deficit		(22,061,177	)		(11,248,483	)
Total Liabilities and Stockholders’ Deficit	$	1,988,075		$	3,476,528
Total Stockholders’ Equity (Deficit)		(2,317,347	)		1,758,420
Total Liabilities and Stockholders’ Equity (Deficit)	$	3,476,528		$	7,557,410

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended April 30,
	2013			2012
	2014			2013
Revenues:
Oil sales	$	~~765~~887,~~548~~087		$	~~758~~765,~~798~~548
Gas sales		4771,~~214~~255			~~183~~47,~~352~~214
Total Revenues		~~812~~958,~~762~~342			~~942~~812,~~150~~762
Operating Expenses:
Lease operating		72116,~~248~~347			8072,~~723~~248
Severance and production taxes		4548,~~668~~041			5045,~~334~~668
Depreciation, depletion, and amortization		~~396~~547,~~319~~704			~~575~~396,~~990~~319
Impairment of oil gas properties		4756,~~758,812~~167			34,~~861~~758,~~083~~812
Exploration		~~80,579~~-			9280,~~247~~579
General and administrative		41,~~219~~494,~~407~~869			54,~~796~~219,~~640~~407
Total Operating Expenses		9,573,033			10,457,017
(Gain) on sale of oil and gas properties		(1,232,279	)		-
Operating Loss		(8,760,271	)		(9,514,867	)
Total Operating Expenses		1,730,849			9,573,033
Operating Loss		(772,507	)		(8,760,271	)
Other Income (Expense):
Interest expense		(1727,~~556,881~~011	)		(1,~~693~~556,~~084~~881	)
Equity in earnings of unconsolidated affiliates		~~(11~~27,~~671~~250	)		35(11,~~060~~671	)
Change in fair value of derivative liability		2328,~~001~~933			-23,001
Losses in connection with conversion of and settlement of debt and accrued liabilities		(465,046	)		-
Gain (Loss) in connection with conversion of debt, settlement of accounts payable and accrued liabilities		413,206			(465,046	)
Loss on sale of assets		(89,847	)		-
(Loss) on sale of assets		-			(89,847	)
Gains in connection with forgiveness of debt and accrued liabilities		~~48,021~~-			-48,021
Miscellaneous income		-			94,643
Net (Loss)	$	(1,030,129	)	$	(10,812,694	)
Net Loss	$	(10,812,694	)	$	(11,078,248	)
Net (Loss) Per Share: Basic and Diluted	$	(0.02	)	$	(0.27	)
Net Loss Per Share: Basic and Diluted	$	(0.27	)	$	(0.34	)
Weighted Average Shares Outstanding: Basic and Diluted		53,811,242			40,714,604
Weighted Average Shares Outstanding: Basic and Diluted		40,714,604			32,824,106

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

STATEMENT OF CHANGES IN STOCKHOLDERS’ ~~EQUITY (~~DEFICIT)

FOR THE YEARS ENDED APRIL 30, ~~2013~~2014 AND ~~2012~~2013

	Common Stock						Additional Paid in		Accumulated
	Shares			Amount			Capital		Deficit			Total
Balances, April 30, 2011		41,400,000		$	41,400		$	13,600	$	(97,800	)	$	(42,800	)
Net loss		-			-			-		(11,078,248	)		(11,078,248	)
Partner distributions		-			-			-		(72,435	)		(72,435	)
Common stock issued for cash		6,240,000			6,240			1,553,760		-			1,560,000
Common stock issued upon exercise of warrants		4,800,000			4,800			2,395,200		-			2,400,000
Common stock issued for acquisition of JHE assets		1,600,000			1,600			398,400		-			400,000
Cancellation of contributed shares		(19,550,000	)		(19,550	)		19,550		-			-
Share-based compensation expense		-			-			4,099,558		-			4,099,558
Beneficial conversion features on convertible notes payable		-			-			1,561,666		-			1,561,666
Common stock issued for acquisition of Redfish Prospect working interest		203,571			204			380,475		-			380,679
Common stock issued for acquisition of WEVCO leases		1,000,000			1,000			2,549,000		-			2,550,000
Balances, April 30, 2012		35,693,571		$	35,694		$	12,971,209	$	(11,248,483	)	$	1,758,420
Net loss		-			-			-		(10,812,694	)		(10,812,694	)
Share-based compensation expense		2,054,833			2,055			2,287,528		-			2,289,583
Common stock and warrants issued for cash		500,000			500			749,500		-			750,000
Common stock issued for lease acquisitions		3,320,035			3,320			2,399,421		-			2,402,741
Common shares issued in connection with debt conversion, modification and conversion of accounts payable and accrued liabilities		2,604,965			2,605			1,291,998		-			1,294,603
Balances, April 30, 2013		44,173,404		$	44,174		$	19,699,656	$	(22,061,177	)	$	(2,317,347	)
Net loss		-			-			-		(1,030,129	)		(1,030,129	)
Share-based compensation expense		12,727,976			12,727			743,201		-			755,928
Common shares issued in connection with debt conversion, modification and conversion of accounts payable and accrued liabilities		15,523,331			15,523			274,036		-			289,559
Balances, April 30, 2014		72,424,711		$	72,424		$	20,716,893	$	(23,091,306	)	$	(2,301,989	)

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended April 30,
	2013			2012
	2014			2013
Cash flows from operating activities
Net loss	$	(10,812,694	)	$	(11,078,248	)
Net (loss)	$	(1,030,129	)	$	(10,812,694	)
Adjustments to reconcile net loss to net cash used in operating activities
Depreciation and depletion expense		~~396~~547,~~319~~704			~~575~~396,~~990~~319
Amortization of discount on notes payable		1,147,742			1,309,296
Accretion of discount on notes payable		290,638			1,147,742
Exploration expense		~~80,579~~-			9280,~~247~~579
Share-based compensation		2521,~~289,537~~555			42,~~099~~289,~~558~~537
Impairment of oil and gas properties		4756,~~758,812~~167			34,~~861~~758,~~083~~812
Equity in earnings of unconsolidated affiliates		~~(89~~-	)		(~~35,060~~89	)
Change in fair value of derivative liabilities		~~(23,001~~864	)		-(23,001	)
Losses in connection with conversion of and settlement of debt and accrued liabilities		465,046			-
(Gain) Loss in connection with conversion of and settlement of debt and accrued liabilities		(443,412	)		465,046
Loss on sale of oil and gas properties		89,847			-
(Gain) Loss on sale of oil and gas properties		(1,232,279	)		89,847
Gains in connection with forgiveness of debt and accrued liabilities		~~(48,021~~-	)		(48,021	)
Changes in operating assets and liabilities
Trade accounts receivable		19(87,~~848~~849	)		~~114~~19,~~203~~848
Prepaid expenses and other assets		~~(22~~19,~~961~~650	)		(1122,~~695~~961	)
Accounts payable		~~643~~(169,~~905~~514	)		~~(58~~643,~~625~~905	)
Accrued liabilities		(~~495~~22,~~118~~308	)		6(495,~~447~~118	)
Bank overdrafts		~~(409,544~~-	)		(409,544	)
Salaries and taxes payable		~~193,965~~-			3193,~~081~~965
Interest payable		~~366~~(48,~~033~~730	)		86366,~~472~~033
Net cash used in operating activities		(1897,~~359,795~~643	)		(~~625~~1,~~707~~359,795	)
Cash flows provided by (used in) investing activities
Acquisitions of oil and gas properties		(~~223~~134,~~945~~915	)		(1223,~~529,800~~945	)
Proceeds received from working interest partners		1,239,629			-
Proceeds received on sale of oil and gas properties		1,897,444			-
Distributions to working interest partners		(416,495	)		-
Proceeds received from working interest partners		468,000			1,239,629
Distributions from equity method investees		12,535			5,449
Distributions to working interest partners		(597,260	)		(416,495	)
Capital expenditures		-			(233,577	)
Distributions from equity method investees		-			12,535
Net cash provided by (used in) investing activities		611,724			(1,757,928	)
Net cash provided by investing activities		1,633,269			611,724
Cash flows from financing activities
Partner distributions		~~(12,446~~-	)		(7212,~~435~~446	)
Proceeds from the issuance of common stock		~~750,000~~-			2750,~~760,~~000
Subscription proceeds received - warrants		~~1,200,000~~-			-1,200,000
Payments on note issued to seller		~~(1,250,000~~-	)		(51,~~000~~250,000	)
Proceeds from convertible notes		~~125~~50,000			4125,~~750,~~000
Net cash provided by financing activities		812,554			2,437,565
Payments on convertible notes		(515,000	)		-
Net increase in cash		64,483			53,930
Net cash provided by (used in) financing activities		(465,000	)		812,554
Net increase in cash		270,626			64,483
Cash
Beginning of year		60125,~~626~~109			660,~~696~~626
End of year	$	~~125~~395,~~109~~735		$	60125,~~626~~109

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended April 30,
	2013		2012
	2014		2013
Supplemental Cash Flow Information:
Cash paid for interest	$	33485,~~453~~103	$	~~297~~33,~~316~~453
Cash paid for income taxes	$	-	$	-
Supplemental Non-Cash Investing and Financing Information:
Settlement of seller note through conveyance of oil and gas properties	$	~~250,000~~-	$	-250,000
Common stock issued for acquisition of WEVCO leases	$	~~578,460~~-	$	2578,~~550,000~~460
Common stock issued for acquisition of Blue Ridge leases	$	~~1,827,700~~-	$	-1,827,700
Common stock issued for settlement of WEVCO liabilities	$	~~41,040~~-	$	-41,040
Common stock issued for settlement of accounts payable	$	~~123~~158,~~500~~022	$	-123,500
Common stock issued in connection with Debt Conversion	$	1126,~~278,189~~762	$	-1,278,189
Common stock issued for acquisition of Redfish Prospect working interest	$	-	$	380,679
Common stock issued for acquisition of JHE assets	$	-	$	400,000
Promissory note assumed for acquisition of JHE assets	$	-	$	5,517,536
Beneficial conversion feature on notes payable	$	-	$	1,561,666

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 30, ~~2013~~2014 and ~~2012~~2013

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Circle Star Energy Corp. (a Nevada Corporation) is a Fort Worth based independent exploration and production company engaged in the acquisition, exploration and development of crude oil and natural gas properties and production of oil and natural gas in the United States.

NOTE 2—GOING CONCERN

At April 30, ~~2013~~2014, we had cash and cash equivalents of $~~125~~395,~~109~~735 and a working capital deficit of $43,~~167~~648,~~097~~330. For the year ended April 30, ~~2013~~2014, we ~~had~~incurred a net loss of $101,~~812~~030,~~694~~129 and an operating loss of $8772,~~760,271 including an impairment of long-lived assets (see Note 7) of $4,758,812~~507. Cash used in operations was $1897,~~359,795~~643.

Given that we have not achieved profitable operations to date, our cash requirements are subject to numerous contingencies and risks beyond our control, including operational and development risks, competition from well-funded competitors, and our ability to manage growth. We can offer no assurance that the Company will generate cash flow sufficient to achieve profitable operations or that our expenses will not exceed our projections. Accordingly, there is substantial doubt as to our ability to continue as a going concern for a reasonable period of time.

There can be no assurance that financing will be available to us when needed or, if available, or that it can be obtained on commercially reasonable terms. Unprecedented disruptions in the credit and financial markets over the past two years have had a significant material adverse impact on access to capital and credit for many companies. Considering our financial condition, we may be forced to issue debt or equity at less favorable terms than would otherwise be available. These disruptions could, among other things, make it more difficult for the Company to obtain, or increase its cost of obtaining capital and financing for its operations. If we are unable to obtain additional or alternative financing on a timely basis and are unable to generate sufficient revenues and cash flows, we will be unable to meet our capital requirements and will be unable to continue as a going concern.

We anticipate generating losses in the near term, and therefore, may be unable to continue operations in the future. To secure additional capital, we will have to issue debt or equity securities or enter into a strategic arrangement with a third party. There can be no assurance that additional capital will be available to us. We currently have no agreements, arrangements, or understandings with any person to obtain funds through bank loans, lines of credit, or any other sources. The financial statements do not include any adjustments that may be necessary if the Company is unable to continue as a going concern.

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The consolidated financial statements include the accounts of Circle Star and our wholly-owned subsidiaries, JHE Holdings, LLC, a Texas limited liability company (“JHE”), and Circle Star Operating Corp., a Nevada corporation (“CSOP”). All material inter-company transactions and accounts have been eliminated in consolidation.

~~Our~~Use ~~financial statements are prepared in accordance with accounting principles generally accepted in the United States~~ of America. The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could differ from those estimates under different assumptions and conditions. Significant estimates are required for, proved oil and gas reserves, the valuation of derivative liabilities, share based compensation, and deferred tax assets.Estimates

38The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements.

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Crude Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.

Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.

Cash and Cash Equivalents

We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash and cash equivalents. We continually monitor our positions with, and the credit quality of, the financial institutions with which we invest.

Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have not experienced any losses related to these balances. ~~Such~~From time to time, such amounts on deposit are ~~not~~ in excess of federally insured limits at April 30, ~~2013~~2014 and ~~2012~~April 30, 2013, respectively.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and long-term debt approximate fair value, as of April 30, ~~2013~~2014 and ~~2012~~April 30, 2013 due to their short maturities.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. Under the successful efforts method, exploration costs and dry hole costs (the primary uncertainty affecting this method) are recognized as expenses when incurred and the costs of successful exploration wells are capitalized as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs (Note 7).

Revenue Recognition

Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser and title transfers to the purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense. For natural gas sales the sale method is utilized in determining whether a sale has occurred.

Accounts Receivable

WeThe ~~recognize~~Company derives revenue ~~for~~primarily ~~our~~from the sale of produced natural gas and crude oil. Revenues from production ~~based~~on properties in which the Company shares an economic interest with other owners are recognized on ~~estimates~~the basis of the Company's interest. ~~Receivables~~Revenues are ~~also~~reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded ~~based~~and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between 30 and 90 days after the date of production. Collection of the revenue may vary depending on the status of wells or the performance of the operator. Estimates of the amount of production delivered to purchasers and the prices at which it was delivered are necessary at year end. Management’s knowledge of the Company’s properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors are the basis for these estimates. Variances between estimates and ~~trued-up~~the toactual ~~actuals~~amounts received are recorded when payment is received, or when better information is available.

~~Production Costs~~32

~~Production~~Table costs, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of ~~operations.~~Contents

~~Exploration~~Concentration ~~expenses~~of ~~include~~Credit ~~dry hole costs, delay rentals, and geological and geophysical costs.~~Risk

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. The Company operates exclusively within the United States of America. For the year ended April 30, 2014, 100% of oil and gas revenue was from non-operated properties where the Company has no direct contact with the actual purchaser. On these properties, our portion of the product was marketed by the multiple companies who operate these wells. In the event of the bankruptcy of any one of these operators we could incur a significant decrease in annual revenue. During the year ended April 30, 2014, three operators, Woodbine Acquisition, CML Exploration and Chesapeake/EXCO accounted for 73%, 15% and 12% of our revenue sales respectively.

Production and Exploration Costs

Production costs, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations. Exploration expenses include dry hole costs, delay rentals, and geological and geophysical costs.

Other Property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives of five years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.

Depreciation expense for other property and equipment was $~~6,596~~nil and $16,~~649~~596, for the years ended April 30, ~~2013~~2014 and ~~2012~~April 30, 2013, respectively.

Asset Retirement ~~Obligation~~Obligations

~~Accounting~~The ~~standards~~Company ~~require~~accounts ~~companies~~for toits ~~record~~asset aretirement ~~liability~~obligations ~~relating~~by torecording the ~~retirement~~fair value of ~~tangible~~a ~~long-lived~~liability ~~assets. When~~for an asset retirement obligation in the ~~liability~~period isin ~~initially~~which ~~recorded,~~a ~~there~~legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. ~~Over~~ ~~time~~Subsequently, the ~~liability is accreted to its present value each period, and the~~ capitalized ~~cost~~asset isretirement ~~depreciated~~costs ~~over~~are ~~the~~charged ~~useful~~to ~~life~~expense ofthrough the ~~related asset. Upon settlement of the liability~~depreciation, ~~either~~depletion ~~the obligation is settled at its recorded amount or a gain or loss is incurred~~ and ~~recognized. As~~amortization of ~~April~~crude ~~30,~~oil ~~2013,~~and ~~management~~natural ~~has~~gas ~~evaluated~~properties ~~its~~and the liability ~~associated~~is ~~with~~accreted ~~its~~to ~~oil~~the ~~and~~expected ~~gas~~future ~~properties~~abandonment ~~and~~cost ~~has~~ratably ~~determined~~over itthe torelated beasset’s ~~insignificant~~life.

39Asset Impairment

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future undiscounted cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method utilizes the most recent third party reserve estimation report and estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate.

Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.

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Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles, or GAAP, and SEC guidelines. The accuracy of a reserve estimate is a function of:

•	the quality and quantity of available data;

•	the interpretation of that data;

•	the accuracy of various mandated economic assumptions;

•	the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

We based the estimated discounted future net cash flows from proved reserves on the un-weighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation, depletion, and amortization expense and our estimates of impairment. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

Share-Based Compensation

The Company follows the fair value recognition provisions of Accounting Standards Codification (“ASC”) 718, “Compensation – Stock Compensation.” The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options and stock awards. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. We estimate the fair value of stock options using the Black-Scholes option pricing model. This model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of our stock price, and the assessment of whether the achievement of performance criteria is probable. The fair value of stock awards is based on the quoted market price on the grant date.

Income Taxes

The Company accounts for income taxes pursuant to the provisions of ASC 740-10, “Accounting for Income Taxes,” which requires, among other things, an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities. A valuation allowance is provided to offset any net deferred tax assets for which management believes it is more likely than not that the net deferred asset will not be realized.

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The Company follows the provisions of the ASC 740-10 related to Accounting for Uncertain Income Tax Positions. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. In accordance with the guidance of ASC 740-10, the benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50 percent likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above should be reflected as a liability for uncertain tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. The Company believes its tax positions are all highly certain of being upheld upon examination. As such, the Company has not recorded a liability for uncertain tax benefits.

The Company has adopted ASC 740-10-25 Definition of Settlement, which provides guidance on how an entity should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits and provides that a tax position can be effectively settled upon the completion of an examination by a taxing authority without being legally extinguished. For tax positions considered effectively settled, an entity would recognize the full amount of tax benefit, even if the tax position is not considered more likely than not to be sustained based solely on the basis of its technical merits and the statute of limitations remains open. As of April 30, ~~2013~~2014, the tax years ended April 30, ~~2012~~2013 and ~~2011~~April 30, 2012 are still subject to audit.

(Loss) per Common Share

Basic net ~~income or~~ loss per common share is computed by dividing the net ~~income or~~ loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net ~~income or~~ loss per common share is calculated in the same manner, but also considers the impact to net ~~income~~loss and common shares for the potential dilution from stock options, stock warrants and any other outstanding convertible securities, or common stock equivalents.

We have issued potentially dilutive instruments as summarized in the table below. We did not include any of these instruments in our calculation of diluted loss per share during the period because to include them would be anti-dilutive due to our net loss during the periods.

The following table summarizes the types of potentially dilutive securities outstanding as of April 30, ~~2013~~2014 and April 30, ~~2012~~2013:

	Year Ended April 30,
	2013		2012
	2014		2013
Common stock awards issuable pursuant to service contract		~~400,000~~-		400,000
Common stock options		~~350,000~~-		~~450~~350,000
Common stock awards		9283,~~182,167~~333		109,~~987~~182,~~000~~167
Convertible notes payable		4,~~123~~080,~~095~~000		34,~~166~~123,~~667~~095
Common stock warrants		5,250,000		-250,000

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Advances from Working Interest Partners

In January 2013, the Company, through its wholly owned subsidiary CSOP, entered into two Participation agreements, whereby the Company became the operator of two wells in Trego County, Kansas. Advances from working interest partners recorded in CSOP as of April 30, 2013 consisted of cash calls received from the other working interest owner, net of costs incurred on the respective wells. As of April 30, 2013 net advances amounted to $188,739.

~~Major~~In ~~Purchasers~~March 2013, the Company, through its wholly owned subsidiary CSOP, received a letter of intent to enter into a Participation agreement, whereby the Company agreed to proceed with gathering seismic data, and ~~Operating~~eventually ~~Region~~become the operator of future potential wells in Trego County, Kansas. The letter of intent was superseded by the Participation agreement finalized on September 13, 2013.

~~The~~In ~~Company~~February ~~operates exclusively within the United States of America. For the year ended April 30~~2014, ~~2013 100% of oil and gas revenue was from non-operated properties where~~ the Company, ~~has~~through noits ~~direct~~wholly ~~contact~~owned ~~with~~subsidiary ~~the actual purchaser. On these properties~~CSOP, ~~our~~entered ~~portion~~into ofa ~~the~~Participation ~~product~~agreement, ~~was~~whereby ~~marketed by~~ the ~~multiple~~Company ~~companies~~became ~~who operate these wells. In~~ the ~~event~~operator of ~~the~~another ~~bankruptcy~~well ~~of any one of these operators we could incur a significant decrease~~ in ~~annual~~Trego ~~revenue. During the year ended April 30~~County, ~~2013 two operators, Woodbine Acquisition and CML Exploration accounted for 54% and 35% respectively~~Kansas.

Advances from working interest partners recorded in CSOP as of April 30, 2014 consisted of cash calls received from the other working interest owner, net of costs incurred on the respective wells. As of April 30, 2014, net advances amounted to $59,479.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its consolidated financial statements.

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Derivative Instruments

The Company may enter into financing arrangements that consist of freestanding derivative instruments or hybrid instruments that contain embedded derivative features. The Company accounts for these arrangements in accordance with ~~Accounting~~ASC ~~Standards Codification~~ Topic 815, Accounting for Derivative Instruments and Hedging Activities ~~(“ASC 815”)~~ as well as related interpretation of this standard. In accordance with this standard, derivative instruments are recognized as either assets or liabilities in the balance sheet and are measured at fair values with gains or losses recognized in earnings. Embedded derivatives that are not clearly and closely related to the host contract are bifurcated and are recognized at fair value with changes in fair value recognized as either a gain or loss in earnings. The Company determines the fair value of derivative instruments and hybrid instruments based on available market data using appropriate valuation models, giving consideration to all of the rights and obligations of each instrument.

We estimate fair values of derivative financial instruments using various techniques (and combinations thereof) that are considered to be consistent with the objective measuring fair values. In selecting the appropriate technique, we consider, among other factors, the nature of the instrument, the market risks that it embodies and the expected means of settlement. For ~~less~~certain complex derivative instruments, such as free-standing warrants and embedded conversion options, we generally use the Black-Scholes model, adjusted for the effect of dilution, because it embodies all of the requisite assumptions (including trading volatility, estimated terms, dilution and risk free interest rates) necessary to fair value these instruments. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques (such as Black-Scholes model) are highly volatile and sensitive to changes in the trading market price of our common stock. Since derivative financial instruments are initially and subsequently carried at fair values, our income (expense) going forward will reflect the volatility in these estimates and assumption changes. Under the terms of the accounting standard, increases in the trading price of the Company’s common stock and increases in fair value during a given financial quarter result in the application of non-cash derivative expense. Conversely, decreases in the trading price of the Company’s common stock and decreases in trading fair value during a given financial quarter result in the application of non-cash derivative income.

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NOTE 4 – FAIR VALUE MEASUREMENTS

~~The~~ASC ~~Company~~Topic ~~has~~820 ~~adopted~~establishes ~~new~~a ~~guidance~~fair ~~under~~value ~~ASC~~hierarchy, ~~Topic~~giving ~~820,~~the ~~Fair~~highest ~~Value~~priority ~~Measurements~~to quoted prices in active markets and ~~Disclosures~~the lowest priority to unobservable data and requires disclosures for assets and liabilities measured at fair value based on their level in the hierarchy. In circumstances in which a quoted price in an active market for the identical liabilities is not available, a reporting entity is required to measure fair value using one or more of the techniques provided for in ASC 820.

ASC Topic 820 establishes a fair value hierarchy, giving the highest priority to quoted prices in active markets and the lowest priority to unobservable data and requires disclosures for assets and liabilities measured at fair value based on their level in the hierarchy. Further new authoritative accounting guidance (ASU No. 2009-05) under ASC Topic 820, provides clarification that in circumstances in which a quoted price in an active market for the identical liabilities is not available, a reporting entity is required to measure fair value using one or more of the techniques provided for in this update.

The standard describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:

●· Level 1 – Quoted prices in active markets for identical assets of liabilities.

●· Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

●· Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.

The Company analyzes all financial instruments with features of both liabilities and equity under ASC 480, “Distinguishing Liabilities from Equity” and ASC 815, “Derivatives and Hedging”. Derivative liabilities are adjusted to reflect fair value at each period end, with any increase or decrease in the fair value being recorded in results of operations as adjustments to fair value of derivatives. The effects of interactions between embedded derivatives are calculated and accounted for in arriving at the overall fair value of the financial instruments. In addition, the fair values of freestanding derivative instruments such as warrant and option derivatives are valued using the Black-Scholes model.

The Company uses Level 3 inputs for its valuation methodology for the derivative liabilities and embedded conversion option liabilities as their fair values were determined by using the Black-Scholes option pricing model based on various assumptions. The Company’s derivative liabilities are adjusted to reflect fair value at each period end, with any increase or decrease in the fair value being recorded in results of operations as adjustments to fair value of derivatives.

The following table sets forth the liabilities as April 30, 2013, which are recorded on the balance sheet at fair value on a recurring basis by level within the fair value hierarchy. As required, these are classified based on the lowest level of input that is significant to the fair value measurement:36

			Fair Value Measurements at Reporting Date Using
Description	April 30, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Convertible promissory notes with embedded beneficial conversion feature	$	63,671		-		-	$	63,671

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The following ~~table~~tables ~~sets~~set forth athe ~~summary~~liabilities ofas ~~changes~~April in30, 2014 and 2013, which were recorded on the balance sheet at fair value ofon ~~our~~a ~~derivative~~recurring ~~liabilities~~basis ~~for~~by level within the ~~years~~fair ~~ended~~value ~~April~~hierarchy. 30As required, ~~2013~~these ~~and~~are ~~April~~classified ~~30,~~based ~~2012~~on the lowest level of input that is significant to the fair value measurement:

	April 30, 2013			April 30, 2012
				Fair Value Measurements at Reporting Date Using
Beginning balance	$	-0-		$	-0-
Description	April 30, 2014			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Embedded conversion option liability recorded in connection with the issuance of convertible promissory notes		86,672			-0-
Convertible promissory notes with embedded beneficial conversion feature	$	-			-		-	$	-
Change in fair value of embedded beneficial conversion feature of convertible promissory notes included in earnings		(23,001	)		-0-
Ending balance	$	63,671		$	-0-

Description	April 30, 2013

Convertible promissory notes with embedded beneficial conversion feature	$	63,671	-	-	$	63,671

The following table sets forth a summary of changes in fair value of our derivative liabilities for the years ended April 30, 2014 and April 30, 2013:

	April 30, 2014			April 30, 2013
Beginning balance	$	63,671		$	-
Embedded conversion option liability recorded in connection with the issuance of convertible promissory notes		83,185			86,672
Changes in derivative liabilities recorded in connection with the conversion of convertible promissory notes		(197,924	)		-
Changes in fair value of embedded beneficial conversion feature of convertible promissory notes included in earnings		51,068			(23,001	)
Ending balance	$	-		$	63,671

NOTE 5—ACQUISITIONS

On June 16, 2011, Circle Star acquired all of the membership interests in JHE from High Plains Oil, LLC (“High Plains”), effective as of June 1, 2011, for consideration including 1,000,000 shares of its common stock (“Common Shares”), a retained profit interest in existing properties valued at $404,101, the assumption of a promissory note in the aggregate amount of $7,500,000, and 600,000 Common Shares.

As a result of the acquisition, JHE’s assets and liabilities were adjusted to their fair values at the acquisition date. No adjustments were made to JHE’s assets and liabilities other than oil and gas properties and the interest in JHE Energy Interests (JHE Units) units as their carrying value approximated fair value at the date of acquisition. As the consideration paid exceeded the fair value of JHE’s net assets, an impairment charge totaling $3,397,693 was recorded at the acquisition date. The calculation of the impairment charge follows:

Fair value of oil and gas properties	$	3,192,372
Investment in JHE Energy Interests		137,604
Note payable, discounted at 28%		(5,517,536	)
Cash payment at closing		(1,000,000	)
Fair value of equity shares granted to sellers		(400,000	)
Working capital acquired		189,867
Impairment charge	$	(3,397,693	)

These assets were acquired in accordance with and in an effort to advance the Company’s business plan. The Company incurred transaction costs of $255,000 during the closing of this acquisition which were recorded as expense in the statement of operations.

On December 6, 2011 the Company entered into a letter agreement (the “Apache Letter Agreement”) with Ingebritson Energy LLC, GTP Energy Partners, LLC, Wind Rush Energy, LLC, Gabriel Barerra and Charles T. Brackett (collectively, the “Apache Sellers”) with a stated execution date of December 1, 2011 (the “Apache Execution Date”). Pursuant to the Apache Letter Agreement, the Company purchased from the Apache Sellers certain interests in oil and gas properties within the Redfish 56 Prospect in Glasscock County, Texas (the “Redfish Properties”). In return, the Apache Sellers received 203,571 Common Shares which, at the Execution Date, had a market value of $1.87 per share. These shares were authorized on January 31, 2012 and issued on March 8, 2012. The Company also assumed the responsibility for payment of certain operating expenses and capital expenditures which were valued at $193,717.

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The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the year ended April 30, 2012, as if the acquisitions of JHE and the Redfish Properties, along with transactions necessary to finance the acquisitions, had occurred on May 1, 2011. The pro forma information includes the effects of adjustments for interest expense, and depreciation and depletion expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of each period presented, nor are they necessarily indicative of future consolidated results.

	For the Year Ended April 30, 2012
Total operating revenue	$	1,066,262
Total operating costs and expenses		6,617,792
Operating loss		(5,551,530	)
Interest expense and other		(420,314	)
Net loss attributed to common stockholders	$	(5,971,844	)
Loss per common share, basic and fully diluted	$	(0.18	)

Colonial Divestiture

On February 6, 2012, the Company sent a Notice of Default and Termination (the “Colonial Notice”) to Colonial stating that Colonial was in breach of its payment obligations under the Colonial Purchase Agreement and that the Company was exercising its right to terminate the Colonial Purchase Agreement. Under the terms of the Colonial Purchase Agreement, the delivery of the Colonial Notice by the Company to Colonial was not deemed to be an election of remedies and the Company retains the right to pursue all legal or equitable remedies against Colonial for breach of the Colonial Purchase Agreement.

Greene Acquisition

On June 19, 2012, the Company filed a petition with the District Court of Clark County, Kansas, Sixteenth Judicial District (Case No. 2012-CV-12) against Greene Brothers Land Company, LLC, Greene Ranch Enterprises, Inc., David M. Greene, Jr., Marcia Greene, Thomas E. Greene, Janice C. Greene, Joseph B. Greene and Billie Greene (collectively the “Defendants”), requesting the return of the deposit, pursuant to the termination of the Greene Agreement. Circle Star terminated the Greene Agreement as a result of defects in title which the Defendants did not cure within the time period set forth in the Greene Agreement. On November 13, 2012, the Company entered into a settlement agreement whereby the pending Greene litigation was settled. The settlement agreement stipulated that Circle Star was to receive $32,500 of the initial deposit from the sellers net of legal fees. The execution of the settlement agreement constitutes a termination of the litigation. The remaining balance of the deposit $17,500 has been charged to impairment expense as of April 30, 2013. On December 11, 2012, we received $22,922 in cash net of legal fees of $9,578 related to the settlement of this matter.

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Wevco Acquisition

On March 6, 2012, the Company entered into a leasehold Purchase Agreement with Wevco Production, Inc. (“Wevco”), whereby Wevco would sell to the Company all of Wevco’s rights, title, and working interest in and to certain oil and gas leases, containing up to 64,575 net acres, situated in Gove and Trego Counties, Kansas (“the Wevco Purchase Agreement”). Under the Wevco Purchase Agreement, the Company was to pay $5,000,000 on or before closing and issue 1,000,000 ~~Common~~common ~~Shares~~shares to the seller. At the time of the signing of the Purchase Agreement, the Company paid $100,000.The Company paid an additional $200,000 in March 2012.These amounts were non-refundable and were considered an advance against the Purchase Price. The Company issued the 1,000,000 ~~Common~~common ~~Shares~~ shares in March 2012.

On April 24, 2012, the Company entered into an amendment to the Wevco Purchase Agreement extending the closing date from April 30, 2012 until May 31, 2012 (the “Wevco First Amendment”). The Company paid a non-refundable $100,000 extension fee which was considered an advance against the Purchase Price.

On June 13, 2012, the Company entered into a Second Amendment to Purchase Agreement extending the closing date from May 31, 2012 until September 28, 2012 (“the Second Amendment”). Pursuant to the Second Amendment, the Company paid a non-refundable $100,000 extension fee, and issued 600,000 ~~Common~~common ~~Shares~~shares. The shares were issued on June 19, 2012 at a price of $0.89 per share. As of July 31, 2012 the Company had capitalized $3,611,638 in costs as deposits subject to forfeiture related to consideration granted the seller.

The Company did not fully execute the terms of the purchase agreement by September 28, 2012. The Seller assigned 1,120 of the 64,575 net acres stipulated in the initial purchase agreement to the Company in October 2012. The value of the acreage transferred to the Company relative to the initial 64,575 net acres as per the terms of the initial Purchase Agreement amounted to $62,641. These costs ~~have~~had been transferred to unproved properties on the Company’s consolidated balance sheet as of April 30, 2013 and the remaining $3,548,997 of deposits subject to forfeiture ~~have~~were ~~been~~ charged to impairment expense.

BlueRidge Acquisition

On April 17, 2012, the Company agreed to purchase certain interests in oil and gas leases in Rawlins, Sheridan and Graham Counties, Kansas for $5,308,375 and 560,000 Common Shares, with a closing date of July 1, 2012. Pursuant to the Purchase Agreement, the Company initially agreed to purchase interests in 17,168 acres in Rawlins County, 12,518 acres in Sheridan County and 12,781 acres in Graham County. The Company paid $50,000 in irrevocable earnest money to be applied to the purchase price at closing.

The Purchase Agreement was amended on July 2, 2012 by which the terms were modified by reducing the acreage of the leases in Graham County by 1,760 acres, and by granting the Company an option to purchase the properties in Rawlins and Graham Counties. The amendment further modified the terms of the Purchase Agreement, whereby the $50,000 of earnest money previously paid was applied to the purchase price and the Company issued 2,611,000 Common Shares to the certain sellers, for the interests in Sheridan County. The shares were issued on July 19, 2012 at a price of $0.70 per share, the fair market value on the date of issuance.

Pursuant to the amendment, the Company had the option to purchase interests in 80,871 acres in Kansas (including the properties in the Rawlins and Graham Counties described above), by making a cash payment of $10,108,875 and by delivering the number of Common Shares equal to $1,000,000, based on the market price of the Common Shares on the date before closing of the Option, on or before September 28, 2012. The Company did not exercise this option.

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On December 18, 2012, the Company and Wevco executed a Settlement and Release Agreement (“Release”). In connection with the execution of the Release the Company issued 225,000 common shares to Wevco at $0.38 per share. The common shares were issued as follows; 115,965 in consideration for the satisfaction of $44,066 in accrued liabilities due Wevco and $109,035 in consideration for approximately 1,400 acres Wevco assigned to the Company. As of April 30, 2014, we had classified $107,574 related to the shares as unproved properties.

BlueRidge Acquisition

On April 17, 2012, the Company agreed to purchase certain interests in oil and gas leases in Rawlins, Sheridan and Graham Counties, Kansas for $5,308,375 and 560,000 common shares, with a closing date of July 1, 2012. Pursuant to the Purchase Agreement, the Company initially agreed to purchase interests in 17,168 acres in Rawlins County, 12,518 acres in Sheridan County and 12,781 acres in Graham County. The Company paid $50,000 in irrevocable earnest money to be applied to the purchase price at closing.

The Purchase Agreement was amended on July 2, 2012 by which the terms were modified by reducing the acreage of the leases in Graham County by 1,760 acres, and by granting the Company an option to purchase the properties in Rawlins and Graham Counties. The amendment further modified the terms of the Purchase Agreement, whereby the $50,000 of earnest money previously paid was applied to the purchase price and the Company issued 2,611,000 common shares to the certain sellers, for the interests in Sheridan County. The shares were issued on July 19, 2012 at a price of $0.70 per share, the fair market value on the date of issuance.

As the Company did not exercise its right to exercise its purchase option, the $50,000 in cash paid and the value of the shares $1,868,632, were reclassified from non-refundable lease deposits to unproved property costs during the quarter ended October 31, 2012. During the fiscal year ended April 30, 2013 $946,895 of the costs were impaired related to a transfer of 50% of the subject acreage related to the settlement of litigation related to this matter in addition $238,880 of the costs related to the acreage were impaired related to lease expirations. During the fiscal year ended April 30, 2014 the remaining value of the lease acreage was impaired due to the short duration remaining on the leaseholds.

NOTE 6—INVESTEES ACCOUNTED FOR UNDER THE EQUITY METHOD

~~The~~Equity ~~Company~~Method has a 10% investment in JHE Energy Interests (“JHEI”) which is accounted for under the equity method of accounting. JHEI is engaged in the exploration, development, and production of oil and gas assets in the state of Texas. The Company’s investment in JHEI was $167,215 and $167,215 for the fiscal years ended April 30, 2013 and 2012, respectively. The Company has elected to use the equity method, as we may have the ability to exercise significant influence on the investee. During the year ended April 30, 2013, we received distributions of $15,805 related to a 10% retained net profits interests in JHEI, and paid distributions of $27,476 to High Plains Oil as part of the acquisition agreement with JHE.Investment

~~NOTE~~The ~~7—OIL~~Company ~~AND~~has ~~GAS~~a ~~PROPERTIES~~10% investment in JHE Energy Interests (“JHEI”) which is accounted for under the equity method of accounting. JHEI is engaged in the exploration, development, and production of crude oil and natural gas assets in the state of Texas. The Company’s investment in JHEI was $167,215 and $167,215 as of April 30, 2014 and April 30, 2013, respectively. The Company has elected to use the equity method, as we may have the ability to exercise significant influence on the investee. During the year ended April 30, 2014, we received earnings distributions of $27,250 related to the investment in JHEI.

~~Capitalized~~The ~~Costs~~table below summarizes activity related to our investment in JHEI for the period ended April 30, 2014

Our oil and gas properties as of April 30, 2013 and April 30, 2012, comprised the following:

Investment in JHEI as of April 30, 2013	$	167,215
Earnings for the year ended April 30, 2014		27,250
Distributions for the year ended April 30, 2014		(27,250	)
Investment as of April 30, 2014	$	167,215

	2013			2012
Proved oil and gas producing properties	$	3,110,292		$	3,435,743
Unproved oil and gas properties		815,589			3,093,727
Accumulated depreciation, depletion and amortization		(912,634	)		(574,341	)
Net capitalized costs	$	3,013,247		$	5,955,129

We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at April 30, 2013 or 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through April 30, 2013, we have capitalized no interest costs because our exploration and development projects generally last less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“BOE”), and one barrel of NGLs to one BOE. The ratios of six Mcf of natural gas to one BOE and one barrel of NGLs to one BOE do not assume price equivalency and, given price differentials, the price for a BOE for natural gas may differ significantly from the price for a barrel of oil. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment amounted to $396,319 and $574,341 for the years ended April 30, 2013 and 2012, respectively.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows.

For 2013, our total impairment expense was $4,758,812, compared to $3,861,083 for 2012.

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~~Significant~~NOTE ~~impairment~~7—CRUDE ~~charges~~OIL ~~recorded~~AND ~~during~~NATURAL ~~the~~GAS ~~year ended April 30, 2013 relate to:~~PROPERTIES

Capitalized Costs

Our crude oil and natural gas properties as of April 30, 2014 and April 30, 2013, comprised the following:

	2014			2013
Proved crude oil and natural gas producing properties	$	2,534,970		$	3,110,292
Unproved crude oil and natural gas properties		107,574			815,589
Accumulated depreciation, depletion and amortization		(1,456,575	)		(912,634	)
Net oil and gas properties	$	1,185,969		$	3,013,247

Capitalized amounts attributable to proved crude oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“BOE”), and one barrel of NGLs to one BOE. The ratios of six Mcf of natural gas to one BOE and one barrel of NGLs to one BOE do not assume price equivalency and, given price differentials, the price for a BOE for natural gas may differ significantly from the price for a barrel of oil. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment amounted to $547,704 and $396,319 for the years ended April 30, 2014 and April 30, 2013, respectively.

Capitalized costs related to-proved crude oil and natural gas properties, including wells on a field by field basis and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to-proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to-proved properties and their estimated fair values based on the present value of the related future net cash flows.

For the year ended April 30, 2014, we recorded impairment expense of $756,167 related to:

(1)	Expiring leased acreage in Sheridan County, Kansas, in the amount of $708,015 previously classified as unproved property associated costs have been impaired; and

(2)	$48,152 related to, on a field by field basis, certain capitalized proved crude oil and natural gas property costs exceeding the fair value of the asset.

For the year ended April 30, 2013, significant impairment charges relate to:

(1)

$3,548,997 recorded in connection with a leasehold Purchase Agreement with Wevco executed in September 2012, whereby Wevco agreed to sell to the Company all of Wevco’s rights, title, and working interest in and to certain oil and gas leases, containing up to 64,575 net acres, situated in Gove and Trego Counties, Kansas (“the Wevco Purchase Agreement”); as further described below.

(2)	Lease expirations in the amount of $238,880, whereby associated costs have been impaired.

(3) Approximately $970,000 in costs associated with acreage transferred in connection with the settlement and release agreement executed in connection with the litigation or of our “Cottonwood” matter. (~~Notes~~Note 14 ~~and 15~~)

Under the Wevco Purchase Agreement, the Company was to pay $5,000,000 on or before closing and issue 1,000,000 Common Shares to the seller. At the time of the signing of the Purchase Agreement, the Company paid $100,000.The Company paid an additional $200,000 in March 2012.These amounts were non-refundable and were considered an advance against the Purchase Price. The Company issued the 1,000,000 Common Shares in March 2012.

On June 13, 2012, the Company entered into a Second Amendment to Purchase Agreement extending the closing date from May 31, 2012 until September 28, 2012 (the “Second Amendment”). Pursuant to the Second Amendment, the Company paid a non-refundable $100,000 extension fee and issued 600,000 Common Shares. The shares were issued on June 19, 2012 at a price of $0.89 per share. As of July 31, 2012, the Company had capitalized $3,611,638 in costs as deposits subject to forfeiture related to consideration granted the seller.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

472014 Transactions

On January 24, 2014, the Company completed the assignment of certain royalty and over-riding royalty interests related to 14 wells located in Madison, Grimes, Dimmit and Fayette counties in Texas to unrelated third parties. Net capitalized costs associated with the interests conveyed amounted to $665,165. Net cash consideration received in connection with the conveyance amounted to $1,897,444. In connection with the conveyance we have recorded a gain of $1,232,279. For the fiscal 2014 year, we had generated revenue of approximately $905,000 related to these interests through the date of the conveyance.

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~~Estimates~~Transfer of ~~Proved~~Net ~~Oil~~Profits ~~and Gas Reserves~~Interest

~~Estimates~~During the fiscal year ended April 30, 2014, the Company made distributions of ~~our~~$1,580 ~~proved~~to ~~reserves~~High ~~included~~Plains inOil, ~~this~~LLC ~~report~~(“High ~~are~~Plains”) ~~prepared~~and $99,774 to an unrelated third party, related to their 10% retained net revenue interest in ~~accordance~~our ~~with~~wholly-owned Usubsidiary, JHE Holdings, LLC (“JHE”). Prior to May 9, 2013, this net revenue interest had been owned by High Plains, an entity controlled by S. ~~generally~~Jeffrey ~~accepted~~Johnson, ~~accounting~~our ~~principles~~Chief Executive Officer. On May 9, or2013, ~~GAAP~~High Plains transferred its ownership of the net revenue interest to an unrelated third party. In February 2014, ~~and~~the ~~SEC~~net ~~guidelines~~revenue interest as held by the unrelated third party increased from 10% to 15%. The ~~accuracy~~increase in the net profits interest was granted in lieu of apaying ~~reserve~~that ~~estimate~~party is$189,000 aor ~~function~~approximately 10% of: the net proceeds received from the January 24, 2014 conveyance of certain over-riding royalty interests and net revenue interests as described above.

•NOTE ~~the~~8—ASSET ~~quality~~RETIREMENT ~~and quantity of available data;~~OBLIGATION

•For the ~~interpretation~~purpose of ~~that~~determining ~~data;~~the fair value of the asset retirement obligation incurred during the year ended April 30, 2014, the Company assumed an inflation rate of 4.07%, an estimated average asset life of 16.5 years, and a credit adjusted risk free interest rate of 7.85%.

•The following reconciles the ~~accuracy~~value of ~~various~~the ~~mandated~~asset ~~economic~~retirement ~~assumptions;~~obligation for the periods presented:

• the judgment of the persons preparing the estimate.

	2014		2013

Asset retirement obligation, beginning of year	$	-	$	-
Liabilities settled		-		-
Liabilities incurred		6,213
Revisions in estimated liabilities		-		-
Accretion		630		-
Asset retirement obligation, end of year	$	6,843	$	-

~~Our~~NOTE ~~proved~~9—NOTES reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.PAYABLE

NOTE 8—NOTES PAYABLE

A summary of our notes payable is as follows:

	April 30, 2013			April 30, 2012
	April 30, 2014			April 30, 2013
(a) Convertible notes payable 10% - February 8, 2013	$	2,750,000		$	2,750,000
(a) Convertible notes payable 12% - December 31, 2014	$	2,310,000		$	2,750,000
(b) Convertible notes payable 10% - March 14, 2013		-			500,000
Debt Discount		(70,635	)		-
(c) Convertible notes payable 10% - August 15, 2014		67,713			-
(b) Convertible notes payable 10% - August 15, 2014		-			67,713
Debt Discount		~~(64,913~~-	)		(~~942~~64,~~213~~913	)
Total Current Portion	$	2,752,800		$	2,307,787
(c) Convertible notes payable 6% - September 14, 2014		1,500,000			-
Long Term
Debt Discount		(43,728	)		-
(d) Convertible notes payable 6% - September 14, 2014	$	1,500,000		$	1,500,000
Total Current Portion	$	3,695,637		$	2,752,800
Debt Discount		(169,288	)		(292,621	)
(c) Convertible notes payable 6% - September 14, 2014	$	-		$	1,500,000
Total Notes Payable	$	4,083,512		$	3,515,166
Debt Discount		-			(169,288	)
Total Long-term Portion	$	-		$	1,330,712
Total Notes Payable	$	3,695,637		$	4,083,512

(a) On February 8, 2012, the Company issued two 10% convertible notes in the aggregate principal amount of $2,750,000. The notes accrue interest at the rate of 10% per annum on the unpaid principal balance and ~~may~~could be repaid by the Company at any time. The notes were originally due and payable on February 8, 2013 or at the election of the applicable holder on the earlier of: (i) the closing of a financing transaction by the Company for aggregate proceeds in excess of $5,000,000; (ii) the sale or partial sale of JHE Holdings LLC (“JHE”); (iii) the sale of all or substantially all of the assets of JHE; or (iv) an Event of Default. The 10% Notes ~~are~~were convertible at the option of the holders into ~~Common~~common ~~Shares~~shares at the Maturity Date or upon the occurrence of one or more of the triggering events set forth above, at a conversion price of $1.50 per share. The notes were discounted by $1,008,333 to reflect the beneficial conversion feature that existed on the date of issuance. On October 9, 2012 the terms of the note were modified whereby interest payments were delayed through February 2013. ~~Further, should the Company close on a $5,000,000 financing, the maturity date of these notes was to be extended through September 30, 2014.~~ In exchange for these modifications the Company issued the noteholders 250,000 ~~Common~~common ~~Shares~~shares (Note 910). In connection with the issuance of these ~~Common~~common ~~Shares~~shares we ~~have~~ recognized a discount to the notes in the amount of $57,500. The discount related to these shares ~~was~~is being amortized over the remaining term of the notes. ~~The remaining unamortized discount related to the beneficial conversion price and the share issuance of as of April 30, 2013 amounted to $0.~~

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The 10% convertible notes became due on February 8, 2013 in the principal amount of $2,750,000. In January 2014 the Company paid a total of $1,000,000 cash, each of the two noteholders receiving $500,000. Of the total amount paid $515,000 was allocated to principal on the notes ($257,500 for each note) and $485,000 was allocated to interest ($242,500 for each note). On February 28, 2014, the Company entered into new note agreements with the two noteholders. The amended and restated note agreements, each in the amount of $1,155,000, accrue interest at 12% per annum and mature on December 31, 2014. The new notes are convertible into shares of the Company’s iscommon stock at $0.75. The new notes are collateralized by a security interest in ~~default~~the oil and is ~~unable~~gas properties held by JHE. The Company has maintained the right to ~~repay~~continue selling interests in assets held by JHE provided that 70% of the proceeds from any sale by JHE be applied to the outstanding principal and accrued interest related to the amended and restated notes. In connection with the new note agreements which extend the term of the notes through December 2014 and increased the interest rate on the notes to 12%, we agreed to issue 5,000,000 shares of our common stock to the noteholders and in connection therewith we recorded a debt discount of $50,000. The Company ~~remains~~at the election of the Chief Executive Officer has retained the right to vote these shares and we have retained the right to re-purchase any or all of these shares at a price of $0.15 per share for six months from the date of grant. In addition we issued to each of the noteholders 2,500,000 warrants to purchase our common shares at $0.05 per share beginning on February 15, 2015. The Company has retained the right to call the warrants any time within the first six months from the date of issuance at $0.10 provided that we repay a minimum of $500,000 in ~~discussion~~principal on each note. In connection with the ~~holders~~issuance of the ~~notes~~warrants we recorded a discount of $38,294. The discount related to the issuance of these warrants is being amortized over the remaining term of the notes. In evaluating whether this transaction should be accounted for as a ~~potential~~debt ~~extension~~modification or extinguishment the Company performed the two step evaluation prescribed in ASC 470-50 and concluded that the transaction should be accounted for as a modification as: (1) the present value of cash flows including non-cash consideration paid did not change by greater than 10% of the carrying amount of the original debt instrument immediately prior to the modification or exchange; and (2) the fair value of the embedded conversion option did not change by greater than 10% of the carrying amount of the original debt instrument immediately prior to the modification or exchange. As of April 30, 2014, the ~~terms~~remaining unamortized portion of the debt discount related to the amended notes amounted to $70,635.

(b) On ~~March~~August 1415, 2012, the Company ~~issued~~entered ~~10%~~into a convertible ~~notes~~note ~~for~~agreement ~~cash~~which inallowed the ~~aggregate~~Company ~~principal~~to ~~amount~~borrow ofup to $~~500~~555,000. The ~~notes~~note ~~accrued~~was ~~interest~~to atmature ~~the~~on ~~rate~~August 15, 2014. The terms of the note contained a 10% ~~per~~or ~~annum~~$55,000 ~~and~~original ~~could~~issuance discount, to be ~~repaid~~pro-rated bybased ~~the~~on ~~Company~~actual atcash ~~any~~drawn ~~time~~in ~~without~~connection with the ~~prior~~instrument. ~~written~~The ~~consent~~note ofwas convertible into common shares at the ~~holders~~lesser of $0.55 ~~The~~or ~~March~~at 10a share value of 75% ~~Notes~~of ~~were~~the ~~due~~lowest ~~and~~closing ~~payable~~share onprice ~~March~~for ~~14,~~the ~~2013~~25 days preceding a conversion. ~~The~~During ~~notes~~the ~~were~~fiscal ~~discounted~~year byended ~~$183~~April 30,~~333~~ as2014, of2014, ~~the~~we ~~date~~received net cash proceeds of ~~issuance~~$50,000 related to anborrowings ~~embedded~~under ~~beneficial~~the ~~conversion~~terms ~~price~~of ~~that~~the ~~existed~~initial onnote ~~the~~agreement. ~~date~~As of ~~issuance.~~January On31, ~~August~~2014, 22we had an outstanding balance of $32,925 ~~2012~~under ~~this~~the terms of the note ~~along~~and ~~with~~recorded ~~accrued~~a ~~interest~~discount in the amount of $1528,~~615~~803 ~~was~~to ~~converted~~be inamortized ~~exchange~~over the term of the note. The note bore no interest for 1the first 90 days and at 10% thereafter. The terms of the note indicated that if any principal were not repaid within 90 days of the initial funding,~~100~~ the 10% interest charge on all outstanding principal was to accrue immediately. Therefore we accrued $5,000 ~~Common~~as ~~Shares~~a component of the principal balance as of January 31, 2014. In addition we recorded $5,000 in original issuance discount and $1,050 in fees as components of the principal balance. In connection with this conversion feature, we ~~have~~ recorded a ~~charge~~derivative ofliability totaling $~~102~~83,~~687~~185 tofor ~~interest~~the ~~expense~~$50,000 draw related to the ~~un-accreted~~Level ~~portion~~III fair value measurement of the ~~debt~~conversion ~~discount~~feature ason the day one issuance of the ~~date~~debt. The value of the associated conversion. Weliability ~~have~~is re-valued at the end of each fiscal period with changes recorded aas charges to our profit and loss. As of ~~$406~~April 30,~~334~~ on2014 ~~conversion~~the entire principal balance of the note had been converted and therefore we recorded a liability of $nil related to the ~~issuance~~embedded conversion feature and recorded gains of $51,068 during the 1fiscal year ended April 30,~~100~~ 2014,~~000~~ ~~shares~~related atto ~~$0.53~~the ~~per~~change ~~share~~in its fair value. ~~The~~We used the Black-Scholes model in establishing the date of issuance fair value and end of reporting period fair value of the conversion ~~feature~~liability. ~~contained~~Key assumptions included in the ~~note~~fair value measurement of this liability included: volatility ranging from 199.51% on the date of issuance, to 310% as of the end of the reporting period; risk free interest rates ranging from 0.13% on the date of issuance, to 0.12% at the ~~notes~~end ~~inception~~of ~~indicated~~the ~~that~~reporting period; and an assumed dividend rate of 0%. In May, June and July 2013, the ~~note~~Company ~~was~~received ~~convertible~~conversion ~~into~~notices ~~333~~from the holders of the $555,~~333~~000 ~~Common~~convertible ~~Shares~~note. ToThe ~~induce~~conversion notices indicated the conversion of $82,838 ~~additional~~in principal, accrued interest and original issuance discount into 2,296,749 common shares ~~were~~at ~~issued~~conversion toprices ~~the~~of ~~noteholder~~$0.053, $0.053, $0.023 and $0.023 per share respectively (Note 10). In December 2013 and January 2014, the ~~value~~Company ~~associated~~received ~~with~~conversion ~~these~~notices ~~additional~~from ~~shares~~the ~~has~~holders ~~resulted~~of inthe $555,000 convertible note. The conversion notices indicated the ~~loss~~conversion onof $28,125 in principal, accrued interest and original issuance discount into 2,700,000 shares of common stock at conversion prices of $0.01875 and $0.075 per share respectively (Note 10).

(c) On August 15, 2012, the Company entered into a $555,000 convertible note agreement. The note matures on August 15, 2014. The terms of the note contain a 10% or $55,000 original issuance discount, to be pro-rated based on actual cash drawn in connection with the instrument. As of April 30, 2013 we had drawn $125,000 under the terms of the note and recorded an original issuance discount in the amount of $13,750 to be amortized over the term of the note resulting in a principal amount due the lender of $137,500. The note bore no interest for the first 90 days and at 10% thereafter. The terms of the note indicate that if principal were not repaid within 90 days of the initial funding, the 10% interest charge on all outstanding principal was to accrue immediately. As of April 30, 2013 we have accrued interest payable in the amount of $13,750. The note is convertible into Common Shares at the lesser of $0.55 or at a share value of 75% of the lowest closing share price for the 25 days preceding a conversion.41

In connection with this conversion feature, we have recorded a derivative liability totaling $86,672 related to the Level III fair value measurement of the conversion feature on the day one issuance of the debt. The value of the associated conversion liability will be re-valued at the end of each fiscal period with changes recorded as charges to our profit and loss. As of April 30, 2013, we have recorded a liability of $63,671 related to the embedded conversion feature and recorded gains of $23,001 related to the change in its fair value. We used the Black-Scholes model in establishing the date of issuance fair value and end of reporting period fair value of the conversion liability. Key assumptions included in the fair value measurement of this liability included: volatility ranging from 74.2% - 98.2% on the date of issuance, to 184% as of the end of the reporting period; risk free interest rates ranging from 0.16%-0.19% on the date of issuance, to 0.11% at the end of the reporting period; and an assumed dividend rate of 0%.

In February, March and April 2013 the Company received conversion notices from the holders of the $555,000 convertible note. The conversion notices indicated the conversion of $69,787 in principal into 550,000 Common Shares at conversion prices of $0.21, $0.16 and $0.09 per share respectively (Note 9). In connection with these conversions we recognized losses on the conversion in the amount of $35,213.

(d) On September 14, 2011, the Company issued 6% convertible notes in the total amount of $1,500,000. The Notes are due and payable on September 14, 2014 and bear interest at the rate of 6% per annum. The Notes are convertible at the option of the holder into Common Shares at a conversion price of $1.50 per share. The Notes are redeemable prior to maturity at the option of the Company and can be repaid in whole or in part at any time without a premium or penalty. Upon issuance, the notes were discounted by $370,000 to reflect the beneficial conversion price that existed on that date. This discount is being accreted over the term of the note payable utilizing the effective interest method. As of April 30, 2013 the remaining unamortized discount related to the notes was $169,288. Interest is payable with the principal on September 14, 2014.

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OnIn ~~June 1~~February, ~~2012,~~March ~~the~~and ~~Company~~April ~~entered into a Note Payment Agreement (the Note Payment Agreement”)~~2014, ~~whereby,~~an ~~the~~additional ~~Company paid~~ $132,~~250,000~~295 ~~and conveyed certain interests~~ in ~~properties~~principal, ~~held~~accrued byinterest ~~JHE~~and ~~that~~original ~~were~~issuance ~~operated~~discount bywas ~~Encana~~converted ~~(“Encana~~into ~~Properties”). The payment of $1~~5,~~250~~526,~~000~~582 ~~and~~shares ~~the conveyance~~ of ~~the~~our ~~Encana~~common ~~Properties~~stock ~~resulted~~at inprices ~~the~~ranging ~~Promissory~~from ~~Note~~$0.0059 into ~~the amount of~~ $~~7,500,000~~0.006 ~~due~~per toshare ~~James~~(Note H10). ~~Edsel,~~The ~~Nancy~~balance ~~Edsel~~on ~~and~~the ~~James~~note Has ~~Edsel~~of ~~Jr.~~April ~~(collectively~~30, ~~the~~2014 ~~“Edsels”)~~was ~~(the~~$0 ~~Edsel~~as ~~Promissory~~all ~~Note”)~~principal ~~being~~accrued ~~fully~~interest ~~paid,~~ and ~~the~~original ~~Company~~issuance ~~was~~discount ~~released~~had ~~from~~been ~~any~~converted ~~further~~as ~~obligations~~of ~~under~~ the ~~Edsel~~end ~~Promissory~~of ~~Note.~~our fiscal year

~~Future~~(c) ~~annual~~On ~~contractual~~September ~~maturities~~14, 2011, the Company issued 6% convertible notes in the total amount of ~~debt~~$1,500,000. The Notes are due and payable on September 14, 2014 and bear interest at the rate of 6% per annum. The Notes are convertible at the option of the holder into common shares at a conversion price of $1.50 per share. The Notes are redeemable prior to maturity at the option of the Company and can be repaid in whole or in part at any time without a premium or penalty. Upon issuance, the notes were discounted by $370,000 to reflect the beneficial conversion price that existed on that date. This discount is being accreted over the term of the note payable utilizing the effective interest method. As of April 30, 2014 the remaining unamortized discount related to the notes was $43,728. Interest is payable with the principal on September 14, 2014. Accrued interest as of April 30, 2014 and 2013 ~~were~~was as$251,890 ~~follows:~~and $147,250, respectively.

Years Ending April 30,	Amounts
2013	$	2,817,713
2014		1,500,000
	$	4,317,713

Future annual contractual maturities of debt as of April 30, 2014 are as follows:

NOTE 9—SHAREHOLDERS’ EQUITY

Years Ending April 30,	Amounts
2015	$	3,810,000

Total future annual contractual maturities of debt	$	3,810,000

~~The~~NOTE 10—SHAREHOLDERS’ ~~Company has authorized 100,000,000 shares of common stock with a par value of $0.001, of which 44,173,404 and 35,693,571 shares were issued and outstanding as of April 30, 2013 and 2012, respectively.~~EQUITY

~~· On March 8, 2013, the Company issued 300,000~~ Common Shares to two directors of the Company. The issuance of these shares represents the completion of the requisite vesting period, with all the expense being recognized during the vesting period. The shares were initially granted at $2.20 per share.Stock

·The OnCompany ~~April~~has 1,authorized ~~2013~~100, ~~the Company issued 504~~000,~~833~~000 ~~Common~~shares ~~Shares~~of tocommon ~~the~~stock ~~Chief Executive Officer in connection~~ with ~~the~~a ~~terms~~par value of ~~his employment agreement~~$0.001, ~~The issuance~~ of ~~these~~which ~~shares~~72,424,711 ~~represents~~and ~~the~~44,173,404 ~~completion~~shares ofwere ~~the~~issued ~~requisite~~and ~~vesting~~outstanding ~~period.~~as ~~The~~of ~~shares~~April ~~were~~30, ~~initially~~2014 ~~granted~~and at2013, $1respectively.~~89 per share.~~

·Activity Onfor ~~April~~the ~~12,~~fiscal ~~2013,~~year ~~the~~ended ~~company~~April ~~issued 250~~30,~~000~~ ~~Common~~2014 ~~Shares~~is ~~to one employee of the Company~~ as the shares issued vested. The issuance of these shares represents the completion of the requisite vesting period, with all expense being recognized during the vesting period. The shares were initially granted at $0.60 per share.follows:

· On ~~March~~May 187, 2013, we issued ~~264~~500,000 ~~Common~~shares ~~Shares~~of common stock at $0.160525 per share, the contractual conversion price, in connection with the ~~settlement~~conversion of ~~accounts~~$26,250 ~~payable.~~in Inprincipal ~~connection~~related ~~with~~to ~~this~~our ~~issuance~~August we14, ~~have~~2014, ~~recorded~~10% aconvertible ~~gain~~notes onpayable. ~~settlement~~(Note ~~in the amount of $23,760.~~9)

· On ~~February~~May 2623, ~~March 7 and April 2,~~ 2013, we issued 50496,~~000,~~429 ~~200,000~~shares ~~and~~of ~~300,000~~common ~~Common~~stock ~~Shares~~ at $0.210525 per share, ~~$0.16~~the ~~per~~contractual ~~share~~conversion ~~and~~price, ~~$0.09 per share. These shares were issued~~ in connection with the conversion of $6926,~~788~~062 ofin principal, original issuance discount and accrued interest on our August 1514, 2014, 10% convertible notes payable. (Note 89).

· On December 18, 2012, the Company issued 325,000 Common Shares valued at $0.38 per share in connection with the settlement of approximately $100,000 in accrued liabilities and accounts payable. In connection therewith we have recognized a loss on the settlement in the amount of $23,500.42

· On December 18, 2012, the Company issued 115,965 Common Shares valued at $0.38 per share in connection with the settlement of $44,066 in accrued liabilities related to the execution of a Settlement and Release agreement (Note 5).

· On December 18, 2012, the Company issued 109,035 Common Shares valued at $0.38 per share in connection with the acquisition of approximately 1,400 acres in Trego County Kansas in connection with the execution of a Settlement and Release agreement (Note 5).

· On October 9, 2012, the Company issued 250,000 Common Shares at $0.23 per share in connection with the modification of $2,750,000 of our convertible notes payable (Note 8). The issuance of the shares extended the repayment date of the accrued interest associated with the notes.

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· On ~~August~~June 2219, ~~2012~~2013, ~~the~~we ~~Company~~ issued 1650,~~100,~~000 ~~Common~~shares ~~Shares~~of common stock at $0.530235 per share, the contractual conversion price, in connection with the conversion of a $~~500~~15,~~000~~259 ~~convertible note payable and associated accrued interest (Note 8). The conversion feature embedded~~ in ~~the~~principal ~~notes~~related ~~initially~~to ~~indicated~~our ~~that~~August ~~the~~14, ~~note~~2014, ~~was~~10% convertible ~~into 333,333 Common Shares~~notes. We(Note ~~have recorded a loss of $406,334 in connection with the additional shares of our common stock.~~9)

· On July 193, ~~2012~~2013, we issued 2650,~~611,000~~320 ~~Common~~shares ~~Shares~~of common stock at $0.700235 per share, the contractual conversion price, in connection with the ~~execution~~conversion of an$15,266 ~~amendment~~in principal, original issuance discount and accrued interest related to aour ~~lease~~August ~~purchase~~14, ~~agreement~~2014, 10% convertible notes payable. (Note 9)

· On June 1927, ~~2012~~2013, we issued ~~600~~757,~~000~~249 ~~Common~~shares ~~Shares~~of common stock to Jeffrey Johnson (“Johnson”) our Chief Executive Officer and President, at $0.8908 per share. 504,833 of these shares were issued in connection with the ~~execution~~completion of arequisite ~~second~~vesting ~~amendment~~requirements, 252,416 shares were issued as share based compensation related to an allowance for the income tax effect of this vesting and a ~~purchase~~previous ~~agreement~~vesting of 504,833 shares. In connection with the issuance of these additional shares we have recorded share based compensation expense in the amount of $10,196.

·	On June 27, 2013, we issued 33,333 shares of common stock to an employee of the Company. The issuance of these shares represents the completion of the requisite vesting period, with all expense being recognized during the vesting period. The shares were initially issued at $2.60 per share.

On June 27, 2013, we issued 1,591,675 shares of common stock at $0.05 per share, the market value of the shares on the date of grant, to Johnson, in connection with the forgiveness of $63,667 in accrued salaries owed Mr. Johnson. In connection with this issuance of shares we have recorded additional share based compensation expense of $15,917, related to an allowance for the income tax effect of the issuance.

On June 27, 2013, we issued 1,568,750 shares of common stock at $0.05 per share, the market value of the shares on the date of grant, to an employee of the Company in connection with the forgiveness of $62,750 in accrued salaries. In connection with this issuance of shares we have recorded share based compensation expense of $15,688, related to an allowance for the income tax effect of the issuance.

·	On July 12, 2013, we issued 103,973 shares of common stock to a former director of the Company. The issuance of these shares represents the completion of the requisite vesting period, with all expense being recognized during the vesting period. The shares were initially granted at $0.60 per share.

On August 30, 2013, we issued 504,834 shares of common stock at $0.04 per share, the market value of the shares on the date of grant, to Johnson. The shares were issued in connection with the completion of the requisite vesting period, with all expense being recognized during the vesting period. An additional 126,208 shares of common stock were issued at $0.04 per share on that same date related to an allowance for the income tax effect of the issuance of the vested shares. In connection with the issuance of the additional shares for the income tax effect we have recorded additional share based compensation expense of $5,048.

·	On December 20, 2013, we issued 700,000 shares of common stock at $0.01875 per share, the contractual conversion price, in connection with the conversion of $13,125 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

·	On January 23, 2014, we issued 2,000,000 shares of common stock at $0.0075 per share, the contractual conversion price, in connection with the conversion of $15,000 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

·	On February 12, 2014, we issued 2,400,000 shares of common stock at $0.006 per share the contractual conversion price, in connection with the conversion of $14,400 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

·	On March 3, 2014, we issued 1,600,000 shares of common stock at $0.0059 per share the contractual conversion price, in connection with the conversion of $9,480 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

·	On March 4, 2014, we issued a total of 5,000,000 common shares, 2,500,000 to each of the holders of our February 8, 2013, 10% convertible notes at $0.0145 per share in connection with the amendment and restatement of the underlying note agreements. (Note 9)

On March 6, 2014, the Board of Directors of the Company resolved to issue 7,758,621 common shares at $0.0145 per share, which was the closing price of our shares on that date, in connection with the issuance bonuses to our Chief Executive Officer, and an employee of the Company (4,310,345 shares and 344,828 shares, respectively). In addition, we issued 3,103,448 shares to an employee of the Company in connection with the satisfaction of accrued salaries payable.

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·	On March 14, 2014, we issued 1,526,582 shares of common stock at $0.0059 per share the contractual conversion price, in connection with the conversion of $4,920 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

On April 12, 2014, we issued a total of 283,333 common shares to employees of the Company. The issuance of these shares represents the completion of the requisite vesting period for these awards, with all expense having been being recognized ratably during the vesting period. The shares were initially granted at $2.60 per share.

Activity for the fiscal year ended April 30, 2013 is as follows:

·	On March 8, 2013, the Company issued 300,000 common shares to two directors of the Company. The issuance of these shares represents the completion of the requisite vesting period, with all the expense being recognized during the vesting period. The shares were initially granted at $2.20 per share.

·	On April 1, 2013, the Company issued 504,833 common shares to the Chief Executive Officer in connection with the terms of his employment agreement. The issuance of these shares represents the completion of the requisite vesting period. The shares were initially granted at $1.89 per share.

On April 12, 2013, the company issued 250,000 common shares to one employee of the Company as the shares issued vested. The issuance of these shares represents the completion of the requisite vesting period, with all expense being recognized during the vesting period. The shares were initially granted at $0.60 per share.

·	On March 18, 2013, we issued 264,000 common shares at $0.16 per share in connection with the settlement of accounts payable. In connection with this issuance we have recorded a gain on settlement in the amount of $23,760.

·	On February 26, March 7 and April 2, 2013, we issued 50,000, 200,000 and 300,000 common shares at $0.21 per share, $0.16 per share and $0.09 per share. These shares were issued in connection with the conversion of $69,788 of our August 15, 2014 10% convertible notes. (Note 9)

·	On December 18, 2012, the Company issued 325,000 common shares valued at $0.38 per share in connection with the settlement of approximately $100,000 in accrued liabilities and accounts payable. In connection therewith we have recognized a loss on the settlement in the amount of $23,500.

·	On December 18, 2012, the Company issued 115,965 common shares valued at $0.38 per share in connection with the settlement of $44,066 in accrued liabilities related to the execution of a Settlement and Release agreement. (Note 5)

·	On December 18, 2012, the Company issued 109,035 common shares valued at $0.38 per share in connection with the acquisition of approximately 1,400 acres in Trego County Kansas in connection with the execution of a Settlement and Release agreement. (Note 5)

·	On October 9, 2012, the Company issued 250,000 common shares at $0.23 per share in connection with the modification of $2,750,000 of our convertible notes payable (Note 9). The issuance of the shares extended the repayment date of the accrued interest associated with the notes.

On August 22, 2012, the Company issued 1,100,000 common shares at $0.53 per share in connection with the conversion of a $500,000 convertible note payable and associated accrued interest (Note 9). The conversion feature embedded in the notes initially indicated that the note was convertible into 333,333 Common Shares. We have recorded a loss of $406,334 in connection with the additional shares of our common stock.

·	On July 19, 2012 we issued 2,611,000 common shares at $0.70 per share in connection with the execution of an amendment to a lease purchase agreement.

·	On June 19, 2012 we issued 600,000 common shares at $0.89 per share in connection with the execution of a second amendment to a purchase agreement.

On May 15, 2012, the Company closed a private placement of units to an Accredited Investor. Under the terms of the private placement, the Company issued 500,000 units at a price of $1.50 per unit, for aggregate cash proceeds of $750,000. Each unit consisted of one Common Share and one half Common Share purchase warrant, each full warrant exercisable to purchase one Common Share at $2.75 for a period of three years. The proceeds were partially used to pay the final payment of the Edsel Promissory Note, the June Extension Price and general corporate purposes.

~~Activity for the fiscal year ended April 30, 2012 is as follows:~~44

· On June 15, 2011, the Company closed a private placement of units. Under the terms of the private placement, the Company issued 4,800,000 units at a price of $0.25 per unit. Each unit consisted of one Common Share and one Common Share purchase warrant, which may be exercised to acquire one Common Share at an exercise price of $0.50 through June 15, 2013. As of the fiscal year ended April 30, 2013, all warrants had been exercised.

· On July 7, 2011, the Company and Felipe A. Pati, a former sole director and officer of the Company, entered into a Contribution Agreement, whereby Mr. Pati contributed 19,550,000 Common Shares as a capital contribution to the Company. The Company and Mr. Pati had determined that it was in the best interest of the Company and its shareholders to adjust the outstanding capital of the Company to facilitate the Company’s ability to raise capital and implement the Company’s expanded business strategy.

· On August 17, 2011, the Company closed a private placement of Common Shares. Under the terms of the private placement, the Company issued 1,440,000 Common Shares at a price of $0.25 per share to "Accredited Investors" (as defined in Rule 501(a) of the Securities Act. The Shares were not, and will not be, registered under the Securities Act, or the laws of any state of the United States. Accordingly, the Shares are “restricted securities” (as defined in Rule 144(a)(3) of the Securities Act) and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act.

· As of April 30, 2012, the Company issued 4,800,000 Common Shares in connection with the exercise of 4,800,000 Common Share purchase warrants at $0.50 per share. The Company received $2,400,000 in proceeds of which $1,200,000 was received in April 2012 and $1,200,000 in May 2012. The Company recorded a receivable of $1,200,000 for those warrants exercised in April 2012 but for which funds were received shortly after the balance sheet date. The warrants were issued on June 15, 2011 in a private placement by the Company of 4,800,000 units at a price of $0.25 per unit, each unit consisted of one Common Share and one Common Share purchase warrant, exercisable to acquire one Common Share at an exercise price of $0.50 through June 15, 2013. These shares are considered issued and outstanding at April 30, 2013 and are included in the Company’s weighted average shares outstanding calculation.

· On October 11, 2011, the Company entered into an executive employment agreement (the “Johnson Employment Agreement”) with Johnson, a director and Chairman of the board of directors (the “Board”) of the Company. Pursuant to the Johnson Employment Agreement, Johnson was appointed to the position of CEO of the Company. The term of the Johnson Employment Agreement is for a two-year period beginning on October 1, 2011 (the “Effective Date”) and ending on the second anniversary of the Effective Date. Under the terms of the Johnson Employment Agreement, Johnson shall be paid a salary of not less than $200,000, annually. Johnson and the Company agreed to an incentive stock compensation arrangement that is anticipated to be linked to the success of the Company’s business and increases shareholder value. Under the terms of the equity compensation, Johnson will be issued Common Shares (each, a “Restricted Share”), upon satisfaction of the following performance based conditions:

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~~(a)~~Unvested ~~Restricted~~Common Share Issuance 1: 1,514,500 Restricted Shares are payable and issued on the following schedule so long as Mr. Johnson is employed or the Johnson Employment Agreement is still effective: 1/3 on March 1, 2012, 1/3 on June 1, 2012, 1/3 on September 1, 2012;Grants

As of April 30, 2014 there were 283,333 shares of unvested common stock issued to employees of the Company outstanding. Shares vest on April 12, 2014 (b250,000) ~~Restricted~~issued ~~Share~~at ~~Issuance~~$0.60 2:and May 1,~~514~~ 2014 (33,~~500~~000) ~~Restricted~~issued ~~Shares~~at ~~are~~$2.60 ~~payable~~respectively. ~~and~~Unvested ~~issued~~share ~~after~~based ~~satisfaction~~compensation as of ~~the~~April ~~following~~30, ~~conditions:~~2014 amounted to $80,562.

~~(1) Daily trading volume of the Company’s common stock exceeds 300,000 for 20 of the last 30 days prior to issuance; and~~Warrants

~~(2)~~Warrant ~~EBITDA~~activities ~~(as~~for ~~defined in~~ the ~~Johnson~~years ~~Employment~~ended ~~Agreement~~April ~~) of the Company exceeds $4~~30,~~000,000~~ ~~during~~2014 ~~any~~and ~~four~~2013 ~~consecutive~~are ~~quarter~~summarized ~~periods~~as ~~during the term of the Johnson Employment Agreement ;~~follows:

(c) Restricted Share Issuance 3: 3,029,000 Restricted Shares are payable and issued after satisfaction of the following conditions:

	Year Ended April 30, 2014						Year Ended April 30, 2013
	Number of Warrants		Weighted Average Exercise Price		Term		Number of Warrants		Weighted Average Exercise Price		Term
Balance at beginning of year		250,000	$	2.75		1.79		250,000	$	2.75		2.79
Issued		5,000,000		0.05		2.0		-		-		-
Exercised		-		-		-		-		-		-
Cancelled		-		-		-		-		-		-
Balance at end of year		5,250,000	$	0.18		1.80		250,000	$	2.75		1.79
Warrants exercisable at end of year		250,000	$	2.75		1.04		250,000	$	2.75		1.79

~~(1)~~During ~~Daily~~the ~~trading~~fiscal ~~volume~~year ofended April 30, 2014, the Company’s ~~common~~issued ~~stock~~to ~~exceeds~~each ~~450~~of the December 31, 2014, 10% noteholders, 2,500,000 ~~for~~warrants 20to ofpurchase ~~the~~our ~~last~~common 30shares ~~days~~at ~~prior~~$0.05 per share, beginning on February 15, 2015. The Company has retained the right to call the warrants any time within the first six months from the date of issuance; ~~and~~at $0.10 provided that we re-pay a minimum of $500,000 in principal on each note.

~~(2)~~The ~~EBITDA~~table ofbelow ~~the~~summarizes ~~Company~~warrants ~~exceeds~~to ~~$6,000,000~~purchase ~~during~~our ~~any~~common ~~four~~shares ~~consecutive~~as ~~quarter~~of ~~periods~~April ~~during~~30, ~~the~~2014 ~~term~~and ofApril ~~the~~30, ~~Johnson Employment Agreement ;~~2013:

(d) Restricted Share Issuance 4: 3,029,000 Restricted Shares are payable and issued after the Company enters into a single Transaction (as defined in the Johnson Employment Agreement) which has a Transaction Value (as defined in the Johnson Employment Agreement) equal to or in excess of $100,000,000.

	2014		2013
Number of warrants		5,250,000		250,000
Exercise price	$	0.05 - $2.75	$	2.75
Expiration date		2015/2016		2015

OnFiscal ~~December~~2014 21, 2011, the Company entered into an amending agreement (the “Pina Amending Agreement”) with G. Jonathan Pina (“Pina”), the former Chief Financial Officer of the Company, to amend the executive employment agreement (the “Pina Employment Agreement”) entered into by the Company and Pina on July 11, 2011 (the “Pina Effective Date”). Pursuant to the Pina Employment Agreement, Pina would receive 500,000 Common Shares (the “Pina Bonus Shares”) on the Effective Date, 500,000 Pina Bonus Shares on the 12 month anniversary of the Pina Effective Date, and 500,000 Pina Bonus Shares on the 24 month anniversary of the Pina Effective Date. The Pina Amending Agreement modified the vesting of the Pina Bonus Shares, whereby Pina would receive 1,000,000 Pina Bonus Shares on the 12 month anniversary of the Pina Effective Date and 500,000 Pina Bonus Shares on the 24 month anniversary of the Pina Effective Date. Pina and the Company rescinded and cancelled the original issuance of the 500,000 Pina Bonus Shares issued on the Pina Effective Date. On December 21, 2011, the market price of the Company’s stock was $2.05 per common share resulting in additional compensation expense to be recognized on a prospective basis of $80,000 through the vesting date of July 31, 2012.Transactions

OnThe ~~February~~assumptions ~~29,~~used ~~2012,~~in the ~~Company~~fair ~~and~~value ~~Johnson~~method ~~entered~~calculation ~~into~~for ~~an amendment to~~ the ~~Johnson~~fiscal ~~Employment~~year ~~Agreement~~ended ~~whereby~~April ~~the~~30, ~~issue~~2014 ~~and~~are ~~payable~~disclosed ~~dates~~in ~~for~~the ~~Restricted~~following ~~Shares~~table. ~~Issuance~~No 1fair ~~(1,514,500~~value ~~restricted~~calculations ~~shares)~~ were ~~amended~~performed toduring ~~1/3~~the onfiscal ~~March~~year 1,ended ~~2013,~~April ~~1/3 on June 1~~30, 2013, ~~1/3~~as onthere ~~September~~were 1,no ~~2013.~~grants:

A summary of the Company’s non-vested stock awards as of April 30, 2013 is presented below:

	Fiscal Year Ended April 30, 2014
Weighted average grant date fair value per warrant granted during the period	$	0.008
Weighted average stock price volatility		306.24	%
Weighted average risk free rate of return		0.11	%
Weighted average expected term	2.00 years
Estimated forfeiture rate	0
Estimated dividend rate	0
Number of warrants	5,000,000

	Shares		Grant Date Fair Value
Non-vested at beginning of period		-	$		-
Granted		9,182,167		1.66
Vested		-		-
Forfeited		-		-
Non-vested at end of period		9,182,167	$	1.66

Expected dividend yield is zero considering that we do not anticipate paying dividends. Volatility is based on the historical volatility of the Company over a period similar to the expected life of the warrants. Expected life is based on the contractual term of the warrants. The risk-free interest rate represents the published interest rate for 2-year US Treasury Bonds on the grant date.

~~Total~~Fiscal ~~unrecognized compensation cost related to the above non-vested, restricted shares amounted to $697,128 and $2,986,711 as of the fiscal years ended April 30,~~ 2013 ~~and 2012, respectively. The cost at April 30, 2013 is expected to be recognized over a weighted-average period of 1.5 years. Related shares are not issued until vested.~~Transactions

52On May 15, 2012 we issued 250,000 warrants to purchase our common shares at $2.75 in connection with a private placement of units to an Accredited Investor.

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NOTE 1011— COMMON STOCK OPTIONS

A summary of the Company’s common-stock options as of April 30, ~~2013~~2014 is presented below:

	Shares			Weighted Average Exercise Price
Beginning Balance		-		$	-
Granted		450,000		$	0.50
Forfeited		-			-
Balance at April 30, 2012		450,000		$	0.50
Exercisable at April 30, 2012		216,666		$	0.50
Balance at April 30, 2012		450,000		$	0.50
Granted		-		$	-
Forfeited		(100,000	)	$	0.50
Balance at April 30, 2013		350,000		$	0.50
Exercisable at April 30, 2013		216,666		$	0.50
Granted		-		$	-
Forfeited		(350,000	)	$	0.50
Balance at April 30, 2014		-		$	-
Exercisable at April 30, 2014		-		$	-

Activity for the fiscal years ended April 30, ~~2013~~2014 and ~~2012~~April 30, 2013 was as follows;:

· On July 611, 2011, ~~David~~Jonathan ~~Brow~~Pina ~~(“Brow”)~~our ~~the~~former ~~then~~Chief ~~sole~~Financial ~~officer~~Officer ofwas granted stock options under the ~~Company~~Plan, ~~was~~consisting ~~granted~~of ~~100~~options to purchase up to an aggregate of 350,000 ~~stock~~shares ~~options~~of ~~under~~ the Company’s ~~2011~~common ~~Stock~~stock ~~Option~~with ~~Plan~~116,666 ~~(the~~stock ~~“Plan”)~~options atvesting anon ~~exercise~~July ~~price~~11, of2012, ~~$0.50.~~116,667 ~~These~~stock options ~~vested~~vesting ~~immediately~~July 11, ~~but~~2013, and 116,667 stock options vesting July 11, 2014. The options were ~~forfeited~~to ~~when~~expire, heJuly ~~resigned~~11, in2022, ~~December~~July ~~2011~~11, 2023, and July 11, 2024, respectively.

· On ~~July~~April 1123, ~~2011~~2013, ~~Pina~~ ~~was~~Mr. ~~granted~~Pina ~~stock~~resigned ~~options~~his ~~under~~position ~~the~~as ~~Plan,~~Chief ~~consisting~~Financial ofOfficer. ~~options~~Accordingly, toas ~~purchase~~per upthe toterms anof ~~aggregate~~the ofPlan ~~350,000~~effective ~~shares~~ninety ofdays ~~the~~from ~~Company~~Mr. Pina’s ~~common~~resignation, ~~stock~~his ~~with 116~~350,~~666~~000 stock options ~~vesting~~were forfeited on July 1123, ~~2012,~~2013. ~~116,667~~As ~~stock~~of ~~options vesting~~ July 1123, 2013 ~~and~~no ~~116,667~~options ~~stock~~to ~~options~~purchase ~~vesting~~the ~~July~~Company’s ~~11,~~common ~~2014~~shares remained issued or outstanding. ~~The~~Total unrecognized compensation cost related to the non-vested common stock options ~~will~~was ~~expire,~~$0 ~~July~~and 11$82,953 ~~2022,~~as ~~July~~of ~~11,~~the ~~2023~~fiscal ~~and~~years ~~July~~ended 11April 30, ~~2024~~2014 and 2013, respectively.

OnNOTE ~~April~~12—INCOME 23, 2013 Mr. Pina resigned his position as Chief Financial Officer. Accordingly as per the terms of the Plan effective ninety days from Mr. Pina’s resignation, his 350,000 stock options were forfeited on July 23, 2013. As of July 23, 2013 no options to purchase the Company’s Common Shares remained issued or outstanding. Total unrecognized compensation cost related to the non-vested common stock options was $82,953 and $254,636 as of the fiscal years ended April 30, 2013 and 2012, respectively. The cost at April 30, 2013, was expected to be recognized over a weighted-average period of 1.25 years. At April 30, 2013 the aggregate intrinsic value for common stock options was $0 and the weighted average remaining contract life was 8.18 years.TAXES

The assumptions used in the fair value method calculation for the fiscal year ended April 30, 2012 are disclosed in the following table. No fair value calculations were performed during the fiscal year ended April 30, 2013 as there were no grants:

	Fiscal Year Ended April 30, 2012
Weighted average grant date fair value per common stock option granted during the period	$	1.43
Weighted average stock price volatility		70.7	%
Weighted average risk free rate of return		0.74	%
Weighted average expected term	2.00 years
Estimated forfeiture rate	0
Estimated dividend rate	0

Expected dividend yield is zero considering that we do not anticipate paying dividends. Volatility is based on an average historical volatility for comparable public reporting companies over a period similar to the expected life of the options. Expected life is based on our judgment of how long the options will be outstanding prior to their exercise. The risk-free interest rate represents the published interest rate for 2-year US Treasury Bonds on the grant date.

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NOTE 11—INCOME TAXES

Income tax expense (benefit) consists of the following as of April 30,

	2013			2012
	2014			2013
Current taxes	$	-		$	-
Deferred taxes		(34,~~879~~558,~~155~~601	)		(3,~~765~~879,~~285~~155	)
Less: valuation allowance		34,~~879~~558,~~155~~601			3,~~765~~879,~~285~~155
Net income tax provision (benefit)	$	-		$	-

The effective income tax rate for the years ended April 30, ~~2013~~2014 and ~~2012~~April 30, 2013 differs from the U.S. Federal statutory income tax rate due to the following:

	2013			2012
	2014			2013
Federal statutory income tax rate		(34.00	%)		(34.00	%)
Permanent differences — disallowed interest on convertible debt		3.6.	%		0.00	%
Permanent differences		1.00	%		3.60	%
Increase in valuation allowance		-37.6	%		-34.00	%
Change in valuation allowance		33.00	%		30.40	%
Net income tax provision (benefit)		-	%		-	%

The components of the deferred tax assets and liabilities as of April 30, ~~2013~~2014 and ~~2012~~April 30, 2013 are as follows:

	2013			2012
	2014			2013
Deferred Tax Assets (Liabilities) - Current	$	-		$	-
Deferred Tax Assets:
Net Deferred Tax Assets (Liabilities) - Current	$	-		$	-
Oil & Gas Properties		447,166			244,719
Deferred Tax Assets (Liabilities) - Noncurrent:
Stock Compensation		2,364,951			2,172,292
Oil & Gas Properties		244,719			175,060
Net Operating Losses		4,356,553			4,072,213
Fixed Assets		-			(2,242	)
Valuation Allowance		(7,168,670	)		(6,489,224	)
Investment in Partnership - JHE		1,155,216			919,834
Net Deferred Tax Assets	$	-		$	-
Stock Compensation		2,172,292			1,393,851
Net Operating Losses		4,072,213			1,278,782
Valuation Allowance		(7,644,440)			(3,765,285	)
Net Deferred Tax Assets (Liabilities) - Noncurrent	$	-		$	-
Net Deferred Tax Asset (Liability)	$	-		$	-

The Company has approximately an $11,977,096 net operating loss carryforward as of April 30, 2013. The net operating losses may offset against taxable income through the year ended April 30, 2033. A portion of the net operating loss carryovers begin expiring in 2032 and may be subject to U.S. Internal Revenue Code Section 382 limitations in the event of certain changes in ownership46

The Company has provided a valuation allowance for the deferred tax asset at April 30, 2013, as the likelihood of the realization of such assets cannot be determined. The valuation allowance increased by $3,879,155 and $3,765,285 for the years ended April 30, 2013 and 2012, respectively.

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~~NOTE~~The Company has approximately a $12~~—SUPPLEMENTAL~~,813,000 ~~OIL~~net ~~AND~~operating ~~GAS~~loss ~~DISCLOSURES~~carryforward ~~(UNAUDITED)~~as of April 30, 2014. The net operating losses may offset against taxable income through the year ended April 30, 2034. A portion of the net operating loss carryovers begin expiring in 2032 and may be subject to U.S. Internal Revenue Code Section 382 limitations in the event of certain changes in ownership.

The ~~following~~Company ~~table~~has ~~sets~~provided ~~forth~~a valuation allowance for the ~~costs~~deferred ~~incurred~~tax inasset ~~oil~~at ~~and~~April ~~gas~~30, ~~property~~2014, ~~acquisition~~as the likelihood of the realization of such assets cannot be determined. The valuation allowance increased by $679,446 ~~exploration~~and $3,879,155 for the years ended April 30, 2014 and ~~development~~2013, ~~activities~~respectively.

	Year Ended April 30,
	2013		2012
Acquisition of Properties:
Proved	$	-	$	7,172,344
Unproved		5,496,568		3,093,727
Exploration Costs		80,579		92,247
Development Costs		223,945		124,482
Total Costs Incurred	$	5,801,092	$	$10,482,800

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by LaRoche Petroleum Consultants, Ltd., Circle Star’s third party reservoir engineering firm. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact. The report was prepared as of April 30, 2013 and is dated August 07, 2013.

	Crude Oil (Bbls)			Natural Gas (Mcf)			Total (BOE)
PROVED-DEVELOPED AND UNDEVELOPED RESERVES:
April 30, 2012		42,615			175,710			71,900
Purchases of reserves in-place		-			-			-
Revisions of previous estimates		(5,279	)		(26,723	)		(10,123	)
Extensions, discoveries, and other additions		21,647			17,150			24,505
Sales of reserves in place		(3,934	)		(130,982	)		(25,734	)
Production		(7,469	)		(8,995	)		(8,968	)
April 30, 2013		47,580			26,160			51,940
PROVED DEVELOPED RESERVES
April 30, 2012		34,645			170,130			63,000
April 30, 2013		39,950			24,050			43,558

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of ASC 932. Future cash inflows at April 30, 2013 were computed by applying the unweighted, arithmetic average on the closing price on the first day of each month for the 12-month period prior to April 30, 2013 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. We had no proved reserves at April 30, 2012.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.

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Future income tax expenses give effect to permanent differences, tax credits and loss carry-forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties. We estimate future income taxes to be zero considering the fact that our tax basis in oil and gas properties and our net operating loss carryforwards for income tax reporting purposes exceed our estimated future net cash inflows.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	As of April 30,
	2013			2012
Future cash inflows	$	4,300,037		$	4,564,193
Future production costs		(948,550	)		(1,117,096	)
Future development costs		(58,350	)		(37,264	)
Future income tax expense		-			-
Future net cash flows		3,293,137			3,409,833
10% annual discount for estimated timing of cash flows		953,457			1,258,123
Standardized measure of discounted future net cash flows related to proved reserves	$	2,339,680		$	2,151,710

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Years Ended April 30,
	2013			2012
Standardized measure, beginning of period	$	2,151,710		$	-
Sales and transfers, net of production costs		(753,846	)		(811,093	)
Net changes in future development costs		2,160			-
Net change in sales and transfer prices, net of production costs		(122,150	)		345,939
Extensions and discoveries and improved recovery, net of future production and development costs		1,553,000			722,147
Revisions of quantity estimates		(263,395	)		(782,833	)
Accretion of discount		215,171			244,925
Sales of reserves in place		(429,012	)		-
Purchase of reserves in-place		-			2,449,250
Changes in production rates (timing) and other		(13,958	)		(16,625	)
Standardized measure, end of period		2,339,680		$	2,151,710

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The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows.

		2013	2012
Oil (per Bbl)	$	88.67	$	92.15
Gas (per mcf)	$	3.12	$	3.63

NOTE 13—RELATED PARTY TRANSACTIONS

~~Pimuro~~On ~~Capital~~June ~~Partners~~16, ~~LLC (“Pimuro”)~~2011, athe ~~consultant~~Company ~~who~~acquired ~~advised~~all ~~High Plains with regards to its acquisition~~ of ~~JHE~~the ~~and~~membership ~~the~~interests ~~Purchase~~in ~~Agreement~~JHE, ~~charged~~effective ~~fees~~as ~~and~~of ~~expenses~~June in1, ~~the~~2011 ~~amount~~from ofHigh ~~$240~~Plains,~~000~~ ~~relating~~an toentity ~~such~~controlled ~~consulting~~by ~~arrangement~~S. ~~between~~Jeffrey ~~High~~Johnson ~~Plains~~(“Johnson”), ~~and~~who ~~Pimuro~~was ~~under~~appointed ~~the~~as ~~terms~~a director of ~~an Installment Agreement (~~the ~~“Installment~~Company ~~Agreement”)~~on ofJune ~~which $100~~16,~~000~~ ~~was~~2011 ~~due~~ and ~~payable~~Chairman onof the ~~closing~~Board ~~date~~on ~~and~~July ~~thereafter~~6, in2011. The ~~monthly~~consideration ~~installments~~for ofJHE ~~$50~~included,~~000,~~ ~~$50,000~~among ~~and~~other ~~$40~~things,~~000~~ ~~commencing~~a ~~when~~10% ~~JHE~~net ~~received~~profits ~~$75,000~~interest in ~~monthly aggregate distribution from~~ JHE ~~Oil~~to ~~and~~be ~~Gas~~retained ~~Properties. Pimuro~~by isHigh ~~controlled by G~~Plains. ~~Jonathan~~On ~~Pina~~May ~~(“Pina”)~~9, ~~who~~2013, ~~was~~High ~~appointed~~Plains astransferred ~~the~~its ~~Company’s~~ownership ~~Chief~~of ~~Financial~~the ~~Officer~~net onprofits ~~July~~interest ~~11,~~in ~~2011~~JHE ~~and~~to ~~subsequently~~an ~~resigned~~unrelated onthird ~~April~~party. During ~~23,~~the ~~2013. As~~fiscal ofyear ended April 30, ~~2013~~2014, ~~all~~the ~~amounts~~Company ~~due~~made ~~and~~distributions ~~payable~~of $1,580 to ~~Pimuro~~High ~~have~~Plains ~~been~~related ~~paid~~to this net profits interest.

OnNOTE ~~June~~14—COMMITMENTS ~~16,~~AND 2011, the Company closed an acquisition under the terms of a Membership Interest Purchase Agreement, effective as of June 1, 2011 (the “Purchase Agreement”), between High Plains and JHE, pursuant to which the Company acquired all of the membership interests in JHE from High Plains (the “Acquisition”). High Plains is an entity controlled by S. Jeffrey Johnson (“Johnson”), who was appointed as a director of the Company on June 16, 2011 and Chairman of the Board on July 6, 2011. On May 1, 2013, Mr. Johnson transferred his ownership of the net profits interest in JHE to an unrelated third party.CONTINGENCIES

Operational Contingencies

The exploration, development and production of oil and gas assets are subject to various, federal and state laws and regulations designed to protect the environment. Compliance with these regulations is part of our day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. We maintain levels of insurance we believe to be customary in the industry to limit its financial exposure. We are unaware of any material capital expenditures required for environmental control during this fiscal year.

Leases

Under the terms of a non-cancellable lease agreement, we lease approximately 1,325 square feet of office space in Fort Worth, Texas, at a cost of $1,300 per month. The primary lease term ~~terminates~~expired on January 31, 2014. ~~Rent~~ We ~~expense~~currently ~~amounted~~lease toour ~~$16,900~~office ~~and~~space ~~$34,351~~on ~~for~~a ~~the~~month ~~years~~to ~~ended~~month ~~April~~basis ~~30, 2013~~ and ~~2012,~~may ~~respectively. As~~terminate ~~of April 30, 2013,~~ the ~~future minimum~~ lease ~~payments~~with ~~related~~two tomonths ~~this~~written ~~agreement are:~~notice.

Year 1		$	11,700
Total		$	11,700

Employment Agreements

We have an outstanding employment agreement with our sole executive officer. Under the terms of this employment agreement Mr. Johnson is to be compensated no less than $200,000 annually through October 13, 2013. Our maximum commitment under the terms of this employment agreement which would apply if the employee covered by this agreement was terminated without cause was 1,009,167 shares of common stock.

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As further described herein (Note 10) 350,000 vested stock options remained eligible for exercise at April 30, 2013, related to an employment agreement with our former Chief Financial Officer. These options were forfeited on July 23, 2013.

NBT Communications Contract

On September 20, 2011, we signed a 12-month contract beginning October 1, 2011, with ChangeWave, Inc., dba NBT Communications, to provide: shareholder acquisition and marketing consulting by means of a project roadmap; institutional investor targeting and presentation review and recommendations; NBT Research reports and updates; social media site management; Web Site/E-letter Sponsorships; NBT and broker dealer conferences; and financial media article/coverage program. We pay a monthly fee of $6,000 per month. NBT would also receive 400,000 shares of common stock upon the achievement of defined contractual milestones.

On March 27, 2013, the Company settled all amounts due, both cash and common stock bonus potential, under the original contract by the issuance of 264,000 Common Shares and recorded prepaid consulting fees through June 30, 2013.

Litigation

Landers

On June 16, 2011, Circle Star acquired all of the outstanding equity interest in JHE. JHE was party to a litigation related to a mineral interest in the well known as Landers #1 (“Landers #1”) that was initiated in November 2008 in the District Court 82nd Judicial District, Robertson County, Texas. The litigation involved a multi-party trespass to try title suit to determine the ownership of Landers #1. Ross L. Martella III originally sought a temporary restraining order, but the lawsuit evolved into a trespass to try title action under Chapter 22 of the Texas Property Code. A Final Judgment was rendered in the suit in November 2010 and it became final and non-appealable in December 2010. Subsequently, two additional litigation matters involving Landers #1 were initiated. As of June 10, 2011, one of the suits was dismissed, and Orbis has agreed to indemnify JHE in connection with the remaining litigation related to Landers #1.

In December 2012, a dismissal without prejudice judgment related to the Landers #1 litigation was executed.

Cottonwood

On or about June 18, 2012, the Company’s registered agent was served with a complaint (Civil Action No. 12-CV-327-CVE-PJC) filed in the United States District Court for the Northern District of Oklahoma by Cottonwood Natural Resources, Ltd. (“Cottonwood”). Cottonwood alleges breach of contract and fraud in connection with a Purchase and Sale Agreement dated April 19, 2012 between the Company and Cottonwood (the “Cottonwood Purchase Agreement”) related to the purchase of certain oil and gas interests in approximately 14,640 acres in Finney County, Kansas (the “Finney Property”). Cottonwood filed the complaint after the Company terminated the Cottonwood Purchase Agreement after the Company determined that Cottonwood had options to title to less than 12,908.46 net acres, and Cottonwood failed to disclose all material facts related to the Finney Property. Cottonwood was seeking damages of at least $4,324,180. On May 31, 2013 a mutual release and settlement agreement was executed by all parties. In connection therewith the Company assigned 4,160 acres in Sheridan County, Kansas to Cottonwood on June 5, 2013. As of April 30, 2013 we recorded impairment expense of $946,895 related to the cost basis of the acreage transferred to Cottonwood.

Greene Litigation

On June 19, 2012, the Company filed a petition with the District Court of Clark County, Kansas, Sixteenth Judicial District (Case No. 2012-CV-12) against Greene Brothers Land Company, LLC, Greene Ranch Enterprises, Inc., David M. Greene, Jr., Marcia Greene, Thomas E. Greene, Janice C. Greene, Joseph B. Greene and Billie Greene (collectively the “Defendants”), requesting the return of the deposit, pursuant to the termination of the Greene Agreement. Circle Star terminated the Greene Agreement as a result of defects in title which the Defendants did not cure within the time period set forth in the Greene Agreement. On November 13, 2012 the Company entered into a settlement agreement whereby the pending Greene litigation was settled. The settlement agreement stipulated that Circle Star was to receive $32,500 of the initial deposit from the sellers net of legal fees. The execution of the settlement agreement constitutes a termination of the litigation. The remaining balance of the deposit $17,500 has been charged to impairment expense as of April 30, 2013. On December 11, 2012 the Company received $22,922 in cash net of legal fees of $9,578 related to the settlement of this matter.

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~~NOTE~~Convertible ~~15—SUBSEQUENT EVENTS~~Notes

On ~~May~~October 928, 2013, ~~Mr.~~the ~~Johnson,~~holders of our ~~Chief~~10% ~~Executive~~convertible ~~Officer~~notes due February 8, ~~transferred~~2013 ~~his~~in ~~ownership~~the principal amount of $2,750,000 filed a legal action against the ~~net~~Company ~~profits~~in ~~interest~~the District Court for Clark County, Nevada, in an attempt to collect the ~~JHE~~outstanding balance related to anthese ~~unrelated~~notes. ~~third~~On ~~party~~February 28, 2014, the Company entered into a settlement agreement and new note agreements with anthe ~~effective~~holders. ~~date~~The ofamended ~~May~~and restated note agreements, each in the amount of $1,155,000, ~~2013~~accrue interest at 12% per annum and mature on December 31, 2014. The Company also issued 5,000,000 shares of its common stock and warrants to purchase an aggregate of 5,000,000 shares to the holders. (Note 8)

OnJonathan ~~May 31, 2013 a mutual release and settlement agreement was executed between the Company and Cottonwood Natural Resources, Ltd~~G. In connection therewith the Company assigned 4,160 acres in Sheridan County, Kansas to Cottonwood on June 5, 2013. This mutual release indicates the end settlement of litigation between the two parties as described elsewhere herein.Pina

On ~~June~~January 1927, ~~2013~~2014 ~~the~~Jonathan ~~Company~~Pina, ~~borrowed~~our ~~$50~~former Chief Financial Officer,~~000~~ ~~under~~filed a legal action against the ~~terms~~Company ofin ~~our~~the ~~10%~~District ~~September~~Court 14of Harris County Texas, ~~2014~~in ~~convertible~~an ~~note~~attempt ~~payable~~to ~~agreement~~collect vacation pay and for alleged failure to pay severance and benefits for resignation with good reason. The Company intends to defend this legal action vigorously.

OnNOTE ~~various~~15—SUPPLEMENTAL ~~dates~~OIL inAND ~~May,~~GAS ~~June~~DISCLOSURES ~~and July, 2013 the holders of our 10%, September 14, 2014 convertible notes converted $82,838 in principal into 2,296,748 Common Shares.~~(UNAUDITED)

OnThe oraggregate ~~about~~amount ~~July~~of 1,capitalized ~~2013~~costs werelated ~~issued~~to ~~3,917,764~~oil ~~Common~~and ~~Shares~~gas toproperty ~~Officers~~ and ~~employees~~the ofaggregate ~~the~~amount ~~Company~~of inrelated ~~connection~~accumulated ~~with~~depletion ~~the~~and ~~extinguishment~~impairment as of ~~accrued~~April ~~salaries~~30, 2014 and ~~payroll~~2013 ~~related~~are ~~liabilities.~~as follows:

Subsequent to April 30, 2013, we remain in negotiation with the holders of our 10%, February 8, 2013 convertible notes payable. The notes have matured and we are currently in discussion with the lender as to potential repayment terms.

	Year Ended April 30,
	2014			2013
Proved properties	$	2,534,970		$	3,110,292
Unproved properties		107,574			815,589
Less accumulated depletion and impairment		(1,456,575	)		(912,634	)
Total oil and gas properties, net	$	1,185,969		$	3,013,247

59The following shows, by category and year incurred, the oil and gas property costs applicable to unproved property that were excluded from the successful efforts depletion computation as of April 30, 2014:

Costs Incurred During Year Ended	Exploration Costs		Development Costs		Acquisition Costs		Impairment			Total Unproved Property
April 30, 2014	$	-	$	-	$	-	$	(708,015	)	$	107,574
April 30, 2013		80,579		-		2,400,095		(4,758,812	)		815,589
Prior Years		92,247		-		3,464,870		(463,390	)		3,093,727
Total	$	172,826	$	-	$	5,864,965	$	(5,930,217	)

The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities.

	Year Ended April 30,
	2014		2013
Acquisition of Properties:
Proved	$	-	$	-
Unproved		5,801,092		5,496,568
Exploration Costs		-		80,579
Development Costs		134,915		223,945
Total Costs Incurred	$	5,936,007	$	5,801,092

Unaudited Oil and Gas Reserves Information

As of April 30, 2014 and 2013, 100% of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm LaRoche Petroleum Consultants, Ltd. Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact. The report was prepared as of April 30, 2014 and is dated July 9, 2014.

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Analysis of Changes in Proved Reserves. Estimated quantities of proved developed and undeveloped reserves (all of which are located within the United States), as well as the changes in proved developed and undeveloped reserves during the periods indicated, are presented in the following tables:

	April 30, 2014						April 30, 2013
	Oil			Gas*			Oil			Gas*
	(Bbls)			(Mcf)			(Bbls)			(Mcf)
Proved Reserves:
Balance, beginning of year		47,580			26,160			42,615			175,710
Revisions of previous estimates (1)		(10,723	)		19,954			(5,279	)		(26,723	)
Extensions and discoveries (2)		43,853			5,626			21,647			17,150
Sales of reserves in place		(6,960	)		(5,534	)		(3,934	)		(130,982	)
Improved recovery		-			-			-			-
Purchase of reserves		-			-			-			-
Production (3)		(9,563	)		(13,070	)		(7,469	)		(8,995	)

Balance, end of year		64,187			33,136			47,580			26,160

Proved developed reserves:
Balance, beginning of year		39,950			24,050			34,645			170,130

Balance, end of year		29,507			31,781			39,950			24,050

Proved undeveloped reserves:
Balance, beginning of year (4)		7,630			2,110			7,970			5,580
PUD Converted to PDP		-			-			-			-
PUD added during the year		33,048			-			-			-
Revisions to previous quantity estimates		(5,998	)		(755	)		(340	)		(3,470	)
Balance, end of year		34,680			1,355			7,630			2,110

	*	Included in Gas (Mcf) above are natural gas liquids (NGL) reserves and are expressed in barrels, multiplied by six the (the conversion of barrels to Mcf).
	1	Revisions of previous estimates – Estimates reflect an overall steady trend of increases in oil and gas prices, offset by normal decline curves in wells.
	2	Extensions and Discoveries – During the fiscal year ended April 30, 2014 consisted of the addition of two new wells that contributed significant volumes in addition to three new wells that were added to the proved undeveloped category.
	3	Production – Volumes of oil and gas that were produced were removed from reserves during the year.
	4	Proved undeveloped reserves - Positive revisions of 26,924 BOE, or 337%, were made to the April 30, 2014 estimated proved undeveloped reserves balance. The primary cause for these revisions was the addition of wells in our April 30, 2014 reserve report that had not been included in our April 30, 2013 reserve report. In addition to underperformance of wells within our areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in our April 30, 2013 reserve report. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in our April 30, 2014 reserve report.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves were prepared in accordance with the provisions of ASC 932. Future cash inflows at April 30, 2014 were computed by applying the un-weighted, arithmetic average on the closing price on the first day of each month for the 12-month period prior to April 30, 2014 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

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Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to crude proved oil and natural gas reserves, less the tax basis of properties involved.

Future income tax expenses give effect to permanent differences, tax credits and loss carry-forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our crude oil and natural gas properties. We estimate future income taxes to be zero considering the fact that our tax basis in oil and gas properties and our net operating loss carryforwards for income tax reporting purposes exceed our estimated future net cash inflows.

The standardized measure of discounted future net cash flows relating to crude proved crude oil and natural gas reserves are as follows:

	As of April 30,
	2014			2013

Future cash inflows	$	6,127,692		$	4,300,037
Future production costs		(2,593,507	)		(948,550	)
Future development costs		(964,894	)		(58,350	)
Future income tax expense		-			-
Future net cash flows		2,569,291			3,293,137
10% annual discount for estimated timing of cash flows		935,715			953,457
Standardized measure of discounted future net cash flows related to proved reserves	$	1,633,576		$	2,339,680

Changes in Standardized Measure of Discounted Future Net Cash Flows

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Years Ended April 30,
	2014			2013

Standardized measure, beginning of period	$	2,339,680		$	2,151,710
Sales and transfers, net of production costs		(880,231	)		(753,846	)
Net changes in future development costs		(51,097	)		2,160
Net change in sales and transfer prices, net of production costs		245,939			(122,150	)
Extensions and discoveries and improved recovery, net of future production and development costs		920,360			1,553,000
Revisions of quantity estimates		(659,150	)		(263,395	)
Accretion of discount		146,958			215,171
Sales of reserves in place		(427,838	)		(429,012	)
Purchase of reserves in-place		-			-
Changes in production rates (timing) and other		(1,045	)		(13,958	)
Standardized measure, end of period	$	1,633,576		$	2,339,680

The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows.

	2014		2013
Crude Oil (per Bbl)	$	98.68	$	88.67
Natural Gas (per mcf)	$	4.03	$	3.12

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

~~Effective March 21, 2013, Hein and Associates, LLP informed the Company that it declined to stand for reappointment as the principal accountant to audit the Company’s financial statements~~None.

Hein’s audit report on the Company’s consolidated financial statements as of and for the year ended April 30, 2012 contained an emphasis paragraph expressing substantial doubt as to the Company’s ability to continue as a going concern. The financial statements did not include any adjustments that might have resulted from the outcome of this uncertainty. Hein’s audit report for the fiscal year ended April 30, 2012 did not otherwise contain any adverse opinion or disclaimer provision and were not otherwise qualified or modified as to audit scope or accounting principles. The audit report of Hein did not contain an opinion on the effectiveness of internal control over financial reporting as of April 30, 2012.

On March 25, 2013, the Company appointed D’Arelli Pruzansky, P.A. as its independent registered public accounting firm (the “New Accountant”). The change in auditor was recommended, approved and ratified by the Company’s Board of Directors.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Management’s Report on Internal Controls Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

-· Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

-· Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

-· Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of the inherent limitations of internal control, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

60As of April 30, 2014, management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") (1992 version) and SEC guidance on conducting such assessments. Based on that evaluation, management concluded that, during the period covered by this report, such internal controls and procedures were not effective based on the COSO criteria. This was due to deficiencies that existed in the design or operation of our internal controls over financial reporting that adversely affected our ability to prepare accurate and timely financial statements, which are considered to be material weaknesses.

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As of April 30, 2013, management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") and SEC guidance on conducting such assessments. Based on that evaluation, management concluded that, during the period covered by this report, such internal controls and procedures were not effective based on the COSO criteria. This was due to deficiencies that existed in the design or operation of our internal controls over financial reporting that adversely affected our ability to prepare accurate and timely financial statements, which are considered to be material weaknesses.

As a public company with listed equity securities, we need to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act or the Dodd-Frank Act, and related regulations of the SEC, which we would not be required to comply with as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses.

The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) lack of a functioning audit committee due to a lack of a majority of independent members and a lack of a majority of outside directors on our board of directors, resulting in ineffective oversight in the establishment and monitoring of required internal controls and procedures; and (2) inadequate segregation of duties consistent with control objectives. The aforementioned material weaknesses were identified by our sole officer in connection with the audit of our financial statements as of April 30, ~~2013~~2014.

Management believes that the material weaknesses set forth above did not have an effect on our financial results. However, management believes that the lack of a functioning audit committee and the lack of a majority of outside directors on the Board results in ineffective oversight in the establishment and monitoring of required internal controls and procedures, which could result in a material misstatement in our financial statements in future periods. See, “Management’s Remediation Initiatives.”

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Attestation Report of the Registered Public Accounting Firm

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to the Dodd-Frank Act and the Company only provided management’s report in this annual report.

Management’s Remediation Initiatives

In an effort to remediate the identified material weaknesses and other deficiencies and enhance our internal controls, we are in the process of formulating a plan to remediate our material weaknesses in internal controls. That plan includes the following:

In ~~October~~May ~~2012~~2014, we engaged a third party consulting firm to ~~supplement~~handle our ~~internal~~day ~~resources~~to ~~with~~day ~~respect~~accounting functions including but not limited to ~~financial~~the ~~reporting~~recording of accounts payable and cash disbursements. We ~~are~~believe ~~further~~that ~~studying~~the ~~best~~utilization ~~practices~~of inthis ~~internal~~third ~~controls~~party ~~over~~will ~~financial~~remediate ~~reporting~~our ~~and~~weakness ~~designing~~related ~~other~~to ~~internal~~lack ~~controls~~of tosegregation ~~implement~~of ~~that~~duties ~~will~~as ~~help~~cited ~~remediate~~above. ~~our weaknesses~~.

Changes in internal controls over financial reporting

Except as noted above, there was no change in our internal controls over financial reporting that occurred during the period covered by this report, which has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Executive Officer and Directors

As of ~~August~~the 13date of this report, our sole officer and director and his age and position is as follows:

Name		Age		Position		Date Of Appointment
S. Jeffrey Johnson		4849		Chief Executive Officer, Interim Chief Financial Officer, Interim Secretary, and Director		Mr. Johnson has served as a director since June 16, 2011, as Chief Executive Officer since October 11, 2011, and as Interim Chief Financial Officer and Interim Secretary since April 25, 2013

S. Jeffrey Johnson

Mr. Johnson was the founder, Chairman and CEO of Cano Petroleum, Inc. from 2004-2011, initially an OTC-listed company which moved to the NYSE/Amex in 2005. Mr. Johnson was CEO of Scope Operating Company from 1998-2004 and was the founder and CEO of Acumen Resources, Inc. from 1993-1998. From 1989-1993, he was Vice President of Touchstone Capital. Mr. Johnson is the managing member of High Plains Oil, LLC, a private oil and gas company he founded in April 2011. Mr. Johnson also previously served on the NYSE/Amex Listed Company Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities and Exchange Act of 1934 requires any person who is our director or executive officer or who beneficially holds more than 10% of any class of our securities which have been registered with the Securities and Exchange Commission, to file reports of initial ownership and changes in ownership with the Securities and Exchange Commission. These persons are also required under the regulations of the Securities and Exchange Commission to furnish us with copies of all Section 16(a) reports they file.

To our knowledge, based solely on our review of the copies of the Section 16(a) reports furnished to us, all Section 16(a) filing requirements applicable to our directors, executive officers and holders of more than 10% of any class of our registered securities were timely complied with during the year ended April 30, ~~2013~~2014, except for the following reports:

Nominating Committee

As of the fiscal year end the Company did not have a nominating committee. The Board as a whole acts as the nominating committee.

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Audit Committee

On July 27, 2012, our Board established an audit committee and adopted an audit committee charter. At present, the Company has a sole officer and director, and the audit committee is not active.

Code of Ethics

The Company is aware of its corporate governance responsibilities and seeks to operate to the highest ethical standards. However, the Company has not adopted a code of ethics to date, as the Company’s management currently consists of a sole officer and director.

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Item 11. Executive Compensation

The following table sets forth information about the remuneration of our principal executive officer for services rendered during our last two completed fiscal years, and our other executive officers that had total compensation of $100,000 or more for our last completed full fiscal year (the “Named Officers”). Certain tables and columns have been omitted as no information was required to be disclosed under those tables or columns.

Summary Compensation Table

Name and Principal Position	Year		Salary ($)		~~Stock Awards ($)~~	Stock Awards ($)	~~Option Awards ($)~~		Option Awards ($)	~~All other Compensation ($)~~		All other Compensation ($)	~~Total ($)~~		Total ($)
S. Jeffrey Johnson, Chief Executive Officer (i)		2012 2013		116,667 191,810	2,862,405 (ii) 954,135			-0- -0-			-0- -0-			2,979,072 1,145,945
S. Jeffrey Johnson Chief Executive Officer (i) (ii) (v)		2013 2014		191,810 196,667			954,135 77,580			-0- -0-			-0- -0-			1,145,945 274,247
G. Jonathan Pina, Chief Financial Officer (iii)		2012 2013		140,323 172,500	2,915,000 (ii) 945,000		500,500 (ii) -0-				-0- -0-			3,555,823 1,117,500
G. Jonathan Pina, Chief Financial Officer (iii) (iv)		2013 2014		172,500 62,397			945,000 -0-			-0- -0-			-0- -0-			1,175,000 62,397

(i)	Mr. Johnson has been the Chief Executive Officer of the Company since October 11, 2011. He became the Interim Chief Financial Officer on April 25, 2013.

(ii) See note 910 of the Company’s consolidated financial statements.

(iii)

Mr. Pina served as Chief Financial Officer from July 11, 2011 to April 23, 2013.

(iv)	Amounts paid to Mr. Pina represent payments made pursuant to previously accrued wages.

(v)	Amounts related to stock awards relate gross up for income taxes on previously vested stock awards, current portion of vesting related to previously issued stock awards, and common shares issued in connection with bonus.

Employment Agreements

G.The ~~Jonathan~~Company ~~Pina~~currently does not have any employment agreements in place.

On July 11, 2011 (“the Pina Effective Date”), the Company entered into an executive employment agreement with Pina in connection with his service as the chief financial officer (the “Pina Employment Agreement”), which provided for an initial annual base salary of $180,000 and a signing bonus of 1,500,000 Common Shares (the “Pina Bonus Shares”), of which 500,000 Bonus Shares vested and were payable on execution of the Pina Employment Agreement, 500,000 Bonus Shares were to vest and be payable 12 months after the Pina Effective Date, and 500,000 Bonus Shares were to vest and be payable 24 months after the Pina Effective Date. The term of the Pina Employment Agreement was for two years from the Pina Effective Date and was to automatically extend by one year unless notice was given 30 days prior to the expiration of the employment period or the agreement was otherwise terminated.

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On December 21, 2011, the Company entered into an amending agreement (the “Pina Amending Agreement”) which modified the vesting of the Pina Bonus Shares, whereby Pina would receive 1,000,000 Pina Bonus Shares on the 12-month anniversary of the Pina Effective Date and 500,000 Pina Bonus Shares on the 24-month anniversary of the Pina Effective Date. Pina and the Company rescinded and cancelled the original issuance of the 500,000 Pina Bonus Shares issued on the Pina Effective Date. On December 21, 2011, the market price of the Company’s stock was $2.05 per common share resulting in additional compensation expense recognized on a prospective basis of $80,000 through the vesting date of July 31, 2012.

In connection with the Pina Employment Agreement, Pina was granted stock options under the Plan, consisting of options to purchase up to an aggregate of 350,000 Common Shares at $0.50 per share with 116,666 stock options vesting 12 months after the Pina Effective Date, 116,667 stock options vesting 24 months after the Pina Effective Date, and 116,667 stock options vesting 36 months after the Pina Effective Date. Pursuant to the terms of the Plan, these stock options were forfeited on July 23, 2013 (90 days after his resignation).

In July 2013, Mr. Pina was granted $62,396 in accrued salary related to his period of employment with the Company.

S. Jeffrey Johnson

On October 11, 2011, the Company entered into an executive employment agreement with Johnson (the “Johnson Employment Agreement”) in connection with his service as the chief executive officer. The term of the Johnson Employment Agreement is for a two-year period beginning on October 1, 2011 (the “Johnson Effective Date”). Under the terms of the Johnson Employment Agreement, Johnson is paid a salary of not less than $200,000 annually. Johnson and the Company agreed to an incentive stock compensation arrangement that is anticipated to be linked to the success of the Company’s business and increases shareholder value. Under the terms of the equity compensation, Johnson is to be issued Common Shares (each, a “Restricted Share”), upon satisfaction of the following performance based conditions:

(a) Restricted Share Issuance 1: 1,514,500 Restricted Shares are payable and issued on the following schedule so long as Johnson is employed or the Johnson Employment Agreement is still effective: 1/3 on March 1, 2012, 1/3 on June 1, 2012, 1/3 on September 1, 2012 (as amended on February 29, 2012 to 1/3 on March 1, 2013, 1/3 on June 1, 2013, and 1/3 on September 1, 2013);

(b) Restricted Share Issuance 2: 1,514,500 Restricted Shares are payable and issued after satisfaction of the following conditions:

(1) Daily trading volume of the Company’s common stock exceeds 300,000 for 20 of the last 30 days prior to issuance; and

(2) EBITDA (as defined in the Johnson Employment Agreement) of the Company exceeds $4,000,000 during any four consecutive quarter periods during the term of the Johnson Employment Agreement;

(c) Restricted Share Issuance 3: 3,029,000 Restricted Shares are payable and issued after satisfaction of the following conditions:

(1) Daily trading volume of the Company’s common stock exceeds 450,000 for 20 of the last 30 days prior to issuance; and

(2) EBITDA of the Company exceeds $6,000,000 during any four consecutive quarter periods during the term of the Johnson Employment Agreement;

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Under the terms of the Johnson Employment Agreement, the employment of Johnson may be terminated with or without cause by either Johnson or the Company with 30 days written notice. If the Company terminates the Johnson Employment Agreement, Johnson will be entitled to earn the Restricted Shares for a period of twelve months following such termination. If Johnson terminates the Johnson Employment Agreement, Johnson shall forfeit any unvested Restricted Shares, except the Restricted Shares issuable under Restricted Share Issuance 1.

Outstanding Equity Awards at Fiscal Year-End

The following table set forth information regarding the outstanding equity awards as of April 30, ~~2013~~2014 for our Named Officers.

Option awards

Stock awards

Number of securities underlying unexercised options (#) exercisable

Number of securities underlying unexercised options (#) unexercisable

Option exercise price ($)

Option expiration date

Number of shares or units of stock that have not vested (#)

Market value of shares or units that have not vested ($)

S. Jeffrey Johnson

-0-

~~1,009,667~~--

~~(i)~~

~~85,822~~--

G. Jonathan Pina

116,666

233,334

0.50

(ii)

500,000

(iii)

42,500

(i) Under the terms of his employment agreement, Mr. Johnson received 1,514,500 restricted shares, of which one-third vested on March 1, 2013, one-third will vest on June 1, 2013 and one-third will vest on September 1, 2013.

(ii) Mr. Pina was granted stock options under the Plan, consisting of options to purchase up to an aggregate of 350,000 Common Shares with 116,666 stock options vesting on July 11, 2012, 116,667 stock options vesting July 11, 2013 and 116,667 stock options vesting July 11, 2014. The options had expiration dates of July 11, 2022, July 11, 2023, and July 11, 2024, respectively, but terminated on July 23, 2013 due to Mr. Pina’s resignation.

(iii) Mr. Pina was to receive 500,000 shares of common stock on July 11, 2013 under the terms of his employment agreement, as amended.

Compensation of Directors

All directors receive reimbursement for reasonable out-of-pocket expenses in attending board of directors meetings and for promoting our business. From time to time we may engage certain members of the board of directors to perform services on our behalf. In such cases, we compensate the members for their services at rates no more favorable than could be obtained from unaffiliated parties. Our sole director Mr. Johnson has been compensated in his capacity as an officer of the Company see summary compensation table above.

The chart below lists director’s compensation for the fiscal year ended April 30, 2013.

Name	Fees earned or paid in cash ($)		Stock awards ($)		Option awards ($)		All other compensation ($)		Total ($)
Thomas Merrill Richards		4,000		330,000		-0-		-0-		334,000
Morris “Sam” B. Smith		4,000		330,000		-0-		-0-		334,000
Elmer Reed		2,000		90,000		-0-	-0-			92,000

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On March 8, 2012, the Board of Directors of the Company approved a compensation package for independent directors which includes 150,000 Common Shares to vest one year after the grant date and terminate if the director is no longer a board member (“Director Shares”), (ii) $1,000 per month per director, and (iii) reimbursement of all out of pocket expenses. The Director Shares were granted to Richards and Smith effective March 8, 2012 and to Reed effective July 16, 2012. Messrs. Richards, Smith and Reed resigned in March 2013.

Compensation Committee

The Company does not have a Compensation Committee. The Board as a whole makes decisions related to compensation.

Compensation Committee Report

The Company does not have a Compensation Committee. The sole director has reviewed the Compensation and Discussion and Analysis and recommended it be included in this Annual Report on 10-K.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table ~~below~~indicates ~~sets forth~~ the ~~number~~beneficial ~~and~~ownership, ~~percentage~~as of ~~shares~~August 5, 2014, of ~~our~~the ~~common~~Company’s ~~stock~~Common ~~owned~~Stock asby: of(i) ~~August~~each 1,director ~~2013,~~and bydirector ~~the~~nominee; ~~following~~(ii) ~~persons:~~each officer; (iiii) ~~stockholders~~each person known toby usthe ~~who~~Company to own more than 5% ~~or more~~ of ~~our~~the outstanding shares, ~~(ii)~~of ~~each~~the ofCompany’s ~~our~~Common ~~Directors,~~Stock; and (~~iii~~iv) ~~our~~all ~~officers~~directors and ~~Directors~~executive officers of the Company as a group. ~~Unless~~Except as otherwise indicated below, ~~each~~all ofshares ~~the~~indicated ~~stockholders~~as ~~has~~beneficially ~~sole~~owned ~~voting~~are ~~and~~held ~~investment power~~ with ~~respect~~sole tovoting ~~the~~and ~~shares~~investment ~~beneficially owned~~power.

Title of Class	Name and Address of Beneficial Owner		Amount and Nature of Beneficial Ownership				Percentage of Class (1)
Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership				Percent of Class (2)
Directors and Named Officers as a group
S. Jeffrey Johnson 7065 Confederate Park Road, Suite 102 Fort Worth, TX 76108 (3)		8,795,144				12.1	%
Common Stock	S. Jeffrey Johnson 7065 Confederate Park Road, Suite 102 Fort Worth, Texas 76108			4,358,590	(2)			8.6	%
Mulligan Family, L.P. 2112 Indiana Avenue Lubbock, TX 79410		5,310, 345				7.3	%
Total for all Directors and Named Officers				4,358,590				8.6	%
Jayme Wollison 7065 Confederate Park Road, Suite 102 Fort Worth, TX 76108 (4)		5,172,198				7.1	%
All officers and directors as a group (1 person)		8,795,144				12.1	%

(21) ~~Includes~~To 1our knowledge,~~000,000~~ ~~shares~~except ~~held~~as ofset ~~record~~forth byin ~~Mulligan~~the ~~Family,~~footnotes ~~L.P.,~~to ~~which~~this istable ~~98%~~and ~~owned~~subject byto ~~Mr.~~applicable ~~Johnson~~community ~~and~~property ~~his~~laws, ~~spouse~~each ~~and~~person ofnamed ~~which~~in the ~~general~~table ~~partner~~has issole ~~West~~voting ~~Texas~~and ~~Investments,~~investment ~~LLC,~~power ~~whose~~with ~~managing~~respect ~~member~~to isthe ~~Mr.~~shares ~~Johnson~~set forth opposite such person’s name.

(2)

This table is based on 72,718,044 shares of Common Stock outstanding as of August 6, 2014. If a person listed on this table has the right to obtain additional shares of Common Stock within sixty (60) days from August 6, 2014, the additional shares are deemed to be outstanding for the purpose of computing the percentage of class owned by such person, but are not deemed to be outstanding for the purpose of computing the percentage of any other person.

(3)

Includes 3,484,799 shares held of record by Mr. Johnson and 5,310,345 shares held of record by Mulligan Family, L.P. Mr. Johnson is the managing member of West Texas Investments, LLC, which is the general partner of Mulligan Family, L.P.

(4)

Does not include 250,000 shares which Mr. Wollison has the right to receive on April 12, 2015.

Changes in Control

There are no existing arrangements that may result in a change in control of the Company.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Other than the transactions discussed below, we have not entered into any transaction nor are there any proposed transactions in which any of our Directors, executive officers, stockholders or any member of the immediate family of any of the foregoing had or is to have a direct or indirect material interest.

66On June 16, 2011, the Company acquired, effective as of June 1, 2011, all of the membership interests in JHE and accordingly, JHE became a wholly-owned subsidiary of the Company. JHE was wholly owned by High Plains, an entity controlled by S. Jeffrey Johnson, who was elected to the Board of Directors of the Company, subsequent to the JHE acquisition, on June 16, 2011. Johnson was appointed as Chairman of the Board on July 6, 2011 and appointed as CEO on October 11, 2011. As part of the JHE acquisition, High Plains was retained a 10% net profits interest in JHE. Mr. Johnson was at arms’ length to the Company prior to his appointment as a director. On May 9, 2013, High Plains transferred its ownership of the net profits interest in JHE to an unrelated third party. During the fiscal year ended April 30, 2014, the Company made distributions of $1,580 to High Plains related to this net profits interest.

On or about July 1, 2013, we issued 3,917,764 common shares to officers and employees of the Company in connection with the extinguishment of accrued salaries and payroll related liabilities.

On or about March 6, 2014 we issued 7,758,621 common shares to officers and employees of the Company in connection with the extinguishment of accrued salaries and payroll liabilities and in connection with a bonus.

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On June 16, 2011, the Company completed the acquisition of JHE in accordance with terms of the JHE Purchase Agreement. Pursuant to the JHE Purchase Agreement, the Company acquired, effective on the JHE Effective Date, all of the membership interests in JHE and accordingly, JHE became a wholly-owned subsidiary of the Company. JHE was wholly owned by Johnson who was elected to the Board of Directors of the Company, subsequent to the JHE Acquisition, on June 16, 2011. Johnson was appointed as Chairman of the Board on July 6, 2011 and appointed as CEO on October 11, 2011. As part of the JHE Acquisition, High Plains, which was wholly owned by Johnson, was issued 1,000,000 Common Shares and the Company paid the $1,000,000 installment payment due June 1, 2011, under a promissory note in the aggregate amount of $7,500,000 issued by High Plains to James H. Edsel, Nancy Edsel, and James H. Edsel, Jr. in connection with the High Plains Acquisition. Mr. Johnson was at arms’ length to the Company prior to his appointment as a director.

On July 6, 2011, David Brow, a director and officer of the Company, was granted an option to purchase 100,000 Common Shares under the Plan at an exercise price of $0.50 per share, which stock option was fully-vested on the date of grant. These options were forfeited when Mr. Brow resigned in December 2011.

In addition, as part of the JHE Acquisition, the Company was required to pay Pimuro, a consultant who advised High Plains with regards to the High Plains Acquisition and the JHE Purchase Agreement, the fees, commissions, and expenses in the amount of $240,000 relating to such consulting arrangement between High Plains and Pimuro under the terms of an Installment Agreement, payable of $100,000 on the closing date and thereafter in monthly installments of $50,000, $50,000, and $40,000 commencing when JHE received $75,000 in monthly aggregate distribution from JHE Oil and Gas Properties. To date these fees have all been paid. Pina, the former Chief Financial Officer of the Company, is a former managing director of Pimuro Capital Partners, LLC. Pina was appointed as Chief Financial Officer of the Company on July 11, 2011. Pina was at arms’ length to the Company prior to his appointment as Chief Financial Officer. See “Item 11 Executive Compensation.”

On October 11, 2011, Johnson was appointed as the Chief Executive Officer of the Company. Johnson was the Chairman of the Board of Directors of the Company when he was appointed as the Chief Executive Officer. See “Item 11 Executive Compensation.” for details of the Johnson Employment Agreement.

On or about July 1, 2013, we issued 3,917,764 Common Shares to officers and employees of the Company in connection with the extinguishment of accrued salaries and payroll related liabilities.

Director Independence

We currently have one director: S. Jeffrey Johnson.

Item 14. Principal Accounting Fees and Services.

D’Arelli Pruzansky, P.A. was appointed as our independent registered public accounting firm in March 2013~~. Hein and Associates, LLP (“Hein”) served as our independent registered public accounting firm for the 2012 fiscal year.~~

Audit Fees

For the fiscal year ended April 30, ~~2013~~2014, D’Arelli ~~and~~ Pruzansky P.A. billed us $4042,000 in audit fees. For the ~~2012~~ fiscal year ended April 30, ~~Hein~~2013 D’Arelli Pruzansky billed us $8840,~~689~~000 infor audit fees.

Audit Related Fees

For the fiscal year ended April 30, ~~2013~~2014, D’Arelli ~~and~~ Pruzansky P.A. billed us $019,500 for audit related fees~~. For the 2012 fiscal year~~, ~~Hein~~which ~~billed~~included usForm ~~$30,768~~10-Q ~~for audit related fees~~reviews.

Tax Fees

For the fiscal ~~year~~years ended April 30, 2014 and 2013, we did not pay any fees to D’Arelli ~~and~~ Pruzansky P.A. for tax compliance, tax advice, or tax planning or other tax related fees. ~~For the 2012 fiscal year, we did not pay any fees to Hein for tax compliance, tax advice or tax planning or other tax related fees.~~

All Other Fees

We did not pay any fees to D’Arelli ~~and~~ Pruzansky P.A. for other work during our fiscal ~~year~~years ended April 30, ~~2013. We~~2014 ~~did~~and ~~not pay any fees to Hein for other work during our 2012 fiscal year~~2013.

Pre-Approval Policies and Procedures

We have implemented pre-approval policies and procedures related to the provision of audit and non-audit services. Under these procedures, our board of directors pre-approves all services to be provided by D’Arelli ~~and~~ Pruzansky. P.A. and the estimated fees related to these services.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

Exhibit	Description
3.1	Articles of Incorporation (included as Exhibit 3.1 to the Form S-1 filed August 6, 2008, and incorporated by reference); and Certificate of Amendment (included as Exhibit 3.1 to the Form 8-K filed on July 1, 2011)
3.2	Amended and Restated Bylaws (included as Exhibit 10.7 to the 8-K filed June 21, 2011, and incorporated by reference)
10.1	Membership Interest Purchase Agreement, dated effective June 10, 2011 (included as Exhibit 10.1 to the Form 8-K filed on June 21, 2011)
4.1	Warrant issued to Mediapark A.G.(included as Exhibit 4.1 to the Form 8-K filed March 4, 2014)
10.2	Amended and Restated Pledge and Security Agreement, dated effective June 10, 2011 (included as Exhibit 10.2 to the Form 8-K filed on June 21, 2011)
4.2	Warrant issued to Soloman AG (included as Exhibit 4.2 to the Form 8-K filed March 4, 2014)
10.3	Novation and Assignment, dated effective June 10, 2011 (included as Exhibit 10.3 to the Form 8-K filed on June 21, 2011)
10.1	Circle Star Energy Corp. 2011 Stock Option Plan (included as Exhibit 10.2 to the Form 8-K filed on July 12, 2011)
10.4	Promissory Note, dated effective January 1, 2011 (included as Exhibit 10.4 to the Form 8-K filed on June 21, 2011)
10.2	Form of 6% Series A Convertible Note (included as Exhibit 10.1 to the Form 8-K filed on September 19, 2011)
10.5	Installment Agreement (included as Exhibit 10.5 to the Form 8-K filed on June 21, 2011)
10.3	Settlement Agreement dated February 28, 2014 by and between Mediapark A.G., Soloman AG, and Circle Star Energy Corp. (included as Exhibit 99.1 to the Form 8-K filed March 4, 2014)
10.6	Form of Subscription Agreement (included as Exhibit 10.6 to the Form 8-K filed on June 21, 2011)
16.1	Letter from Hein & Associates LLP dated March 27, 2013 (included as Exhibit 16.1 to the Form 8-K filed on March 27, 2013)
10.7	Contribution Agreement entered into between Felipe Pati and the Company (included as Exhibit 10.1 to the Form 8-K filed on July 12, 2011)
23.1	Consent of LaRoche Petroleum Consultants, Ltd.
10.8	Circle Star Energy Corp. 2011 Stock Option Plan (included as Exhibit 10.2 to the Form 8-K filed on July 12, 2011)
31.1	Certification of the Principal Executive, Financial and Accounting Officer pursuant to Rule 13a-14(a) of the Exchange Act
10.9	G. Jonathan Pina Employment Agreement (included as Exhibit 10.1 to the Form 8-K filed on July 13, 2011)
32.1	Certification of Principal Executive, Financial and Accounting Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
10.10	Consulting Agreement effective June 15, 2011, between Big Sky Management Ltd. and Digital Valleys Corp. (included as Exhibit 10.10 to the Annual report on Form 10-K/A filed on August 16, 2011)
99.1	Report of LaRoche Petroleum Consultants dated July 9, 2014
10.11	Form of 6% Series A Convertible Note (included as Exhibit 10.1 to the Form 8-K filed on September 19, 2011)
101.INS	XBRL Instance Document
10.12	Executive Employment Agreement entered into between the Company and S. Jeffrey Johnson (included as Exhibit 10.1 to the Form 8-K filed on October 14, 2011)
101.SCH	XBRL Taxonomy Extension Schema Document
10.13	Letter Agreement dated December 1, 2011 (included as Exhibit 10.1 to the Form 8-K filed on December 7, 2011)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
10.14	Amending Agreement among the Company and G. Jonathan Pina entered into on December 21, 2011 (included as Exhibit 10.1 to the Form 8-K filed on December 23, 2011)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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10.15	Membership Interest Purchase Agreement between the Company and Colonial Royalties, LLC dated December 30, 2011 (included as Exhibit 10.1 to the Form 8-K filed on January 5, 2012)
10.16	Amending Agreement among the Company and S. Jeffrey Johnson entered into on February 29, 2012 (included as Exhibit 10.1 to the Form 8-K filed on March 6, 2012)
10.17	Form of 10% Convertible Note (February 2012) (included as Exhibit 10.15 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.18	Inter-Creditor Agreement (included as Exhibit 10.16 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.19	First Amendment to Assignment and Novation Agreement (included as Exhibit 10.17 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.20	First Amendment to Amended and Restated Membership Interest Pledge and Security Agreement (included as Exhibit 10.18 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.21	Leasehold Purchase Agreement dated March 8, 2012 (included as Exhibit 10.19 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.22	Form of 10% Convertible Note (March 2012) (included as Exhibit 10.20 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.23	Addendum to March 2012 Convertible Note Subscription Agreement (included as Exhibit 10.21 to the Quarterly Report on Form 10-Q filed on March 16, 2012)
10.24	Amendment to Leasehold Purchase Agreement dated April 24, 2012 among the Company and Wevco Production, Inc. (included as Exhibit 10.1 to the Current Report on Form 8-K filed on April 30, 2012)
10.25	Second Amendment to Leasehold Purchase Agreement dated June 12, 2012 among the Company and Wevco Production, Inc. (included as Exhibit 10.1 to the Current Report on Form 8-K filed on June 19, 2012)
10.26	Purchase and Sale Agreement dated April 17, 2012 (included as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 13, 2012)
10.27	Amendment to the Purchase and Sale Agreement dated July 9, 2012 (included as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 13, 2012)
10.28	Debt Conversion Agreement (included as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 30, 2012)
10.29	Form of Note Extension Agreement (included as Exhibit 10.29 to the Company’s registration statement on Form S-1 filed January 18, 2013)
16.1	Letter from Hein & Associates LLP dated March 27, 2013 (included as Exhibit 16.1 to the Form 8-K filed on March 27, 2013)
23.1	Consent of LaRoche Petroleum Consultants, Ltd.
23.2	Consent of Hein & Associates LLP
23.3	Consent of D’Arelli Pruzansky, P.A.
31.1	Certification of the Principal Executive, Financial and Accounting Officer pursuant to Rule 13a-14(a) of the Exchange Act
32.1	Certification of Principal Executive, Financial and Accounting Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Report of LaRoche Petroleum Consultants dated August 7, 2013

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101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

InPursuant ~~accordance~~to ~~with~~the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	CIRCLE STAR ENERGY CORP.
August 13, 2013	By:	/s/ S. Jeffrey Johnson
August 8, 2014	By:	/s/ S. Jeffrey Johnson
		S. Jeffrey Johnson
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, ~~as amended,~~ this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.

Signatures	Title	Date
/s/ S. Jeffrey Johnson	Principal Executive, Financial and Accounting Officer and Director	August 138, ~~2013~~2014
S. Jeffrey Johnson

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Number of Late Reports

Transactions Not Timely Reported

Known Failures to File a Required Form

S. Jeffrey Johnson

G. Jonathan Pina

Thomas Merrill Richards

Morris “Sam” B. Smith

Elmer Reed