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, 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	98-05737383
(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: $1,475,651.

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 8, 2014 we had 72,718,044 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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TABLE OF CONTENTS

		Page
PART I

Item 1.	Business	8
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	12
Item 2.	Properties	12
Item 3.	Legal Proceedings	15
Item 4.	Mine Safety Disclosures	15

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6.	Selected Financial Data	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	51
Item 9A.	Controls and Procedures	51
Item 9B.	Other Information	52

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	53
Item 11.	Executive Compensation	54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13.	Certain Relationships and Related Transactions, and Director Independence	55
Item 14.	Principal Accounting Fees and Services	56

PART IV

Item 15.	Exhibits, Financial Statement Schedules	57

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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.

“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.

“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” – Reserves include shut-in and behind-pipe 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 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, 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.

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 acquired all of the membership interests in JHE Holdings, LLC, a Texas limited liability company (“JHE”), effective as of June 1, 2011, from High Plains Oil, LLC, a Nevada limited liability company (“High 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 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.

The assumed promissory note was secured by all of the membership interests in JHE and was fully paid by the Company as follows: 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.

Redfish Properties Acquisition

On December 6, 2011, the Company acquired interests in oil and gas properties within the Redfish 56 Prospect in Glasscock County, Texas, effective November 1, 2011, in consideration for 203,571 shares of the Company’s common stock and the assumption of the responsibility for payment of certain operating expenses and capital expenditures.

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 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 shares in March 2012.

The Company entered into two amendments to the Wevco Purchase Agreement to extend the original April 30, 2012 closing date to September 28, 2012 and paid a total of $200,000 in extension fees and issued 600,000 shares of the Company’s common stock. As of July 31, 2012, the Company had capitalized $3,611,638 in costs as deposits subject to forfeiture related to consideration paid to 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 been transferred to unproved properties on the Company’s consolidated balance sheet as of April 30, 2014 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 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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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 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 shares of the Company’s common stock to the 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.

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 related lease expirations.

Circle Star Operating

Circle Star Operating Corp., a Nevada corporation (“CSOP”) was formed on June 12, 2012. Through CSOP we have entered into several participation agreements whereby we have drilled and are the operator of record of three wells in Trego County, Kansas.

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.

On-Going Activities

Texas

The Company owns a variety of non-operated working interests and overriding royalty interests in approximately 61 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), EXCO (Eagle Ford Shale), CML (Giddings, Pearsall and Permian), Leexus (Giddings) and MD America Energy, LLC. (Woodbine). As of April 30, 2014, the Company had approximately 430 net leased acres in Texas.

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Kansas

The Company operates 3 producing wells in Trego County, Kansas. The Company owns between a 25% and 55% working interest in these three wells. Subsequent to the end of the fiscal year the Company has drilled an additional well, which is currently 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, 2014, our proved reserves in BOE increased to 69,710 from 51,940 or 34% and PV-10 decreased from $2,339,680 to $1,633,576 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.

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, 2014, approximately 88% 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, 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.

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, all of which are 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, 2014, we owned interests in 64 gross producing wells in two states.

State and Well Information

Texas County	Producing Wells*		Net Well Count
Texas		61.00		0.64
Kansas		3.00		1.05
Total*		64.00		1.69

*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.”

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.

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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, 2014, by the LaRoche Petroleum Consultants, Ltd. (“LRPC”) of Richardson, Texas. As of April 30, 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 July 9, 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, 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, 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.

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 2014 and 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,
	2014		2013
Production
Oil (Bbls)		9,563		7,469
Gas (Mcf)		13,070		8,995
Total (BOE)		11,741		8,968
Total (BOE/d)		32		25
Average prices
Oil (per Bbl)	$	92.76	$	102.50
Gas (per Mcf)		5.45		5.25
Total (per BOE)	$	81.62	$	90.63
Production Costs per BOE	$	9.91	$	8.06

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Drilling Activity

The following table sets forth information on our drilling activity for the fiscal 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.

	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells

Productive		2.0		0.57		3.0		0.48		21.00		0.19
Dry		-		-		-		-		1.0		0.01
Total		2.0		.57		3.0		0.48		22.0		0.20

Of the 2 gross (0.57 net) wells drilled in 2014, all were completed as of April 30, 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 we have recently completed the drilling of a well in Trego County Kansas in which we have a 60% net working interest. This well is currently 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, 2014. Wells are classified as natural gas or oil according to their predominant production stream.

	Gross		Net
Oil		64.00		1.69
Gas		0.00		0.00
Total		64.00		1.69

Acreage

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

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Texas		24,962		275		19,026		155		43,988		430
Kansas		320		320		5,800		5,800		6,120		6,120
Total		25,282		595		24,826		5,955		50,108		6,550

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’s interest.

Convertible Notes

On October 28, 2013, the holders of our 10% convertible notes due February 8, 2013 in the principal amount of $2,750,000 filed a legal action against the Company in the District Court for Clark County, Nevada, in an attempt to collect the outstanding balance related to these notes. On February 28, 2014, the Company entered into a settlement agreement and new note agreements with the holders. 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 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.

Jonathan G. Pina

On January 27, 2014 Jonathan Pina, our former Chief Financial Officer, filed a legal action against the Company in the District Court of Harris County Texas, in an attempt to 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.

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 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 7, 2014, as reported by the OTCBB was $0.01.

Holders of our Common Stock

On August 7, 2014, the shareholders’ list of our common stock had 70 registered shareholders and 72,718,044 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, 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		-		-		3,000,000
Total		-		-		3,000,000

Recent Sales of Unregistered 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 was required to implement this guidance effective for the first quarter of fiscal 2014 the adoption of ASU 2011-11 did not have a material impact on 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.

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, 2014 and April 30, 2013, respectively. We had no crude oil and natural gas operations prior to the fiscal year beginning May 1, 2011. We determined the BOE using the ratio of six Mcf of natural gas to one BOE. The ratio 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 or NGLs may differ significantly from the price for a barrel of oil.

	Year Ended April 30,
	2014		2013
Revenues
Oil	$	887,087	$	765,548
Gas (1)		71,255		47,214
Total oil and gas sales	$	958,342	$	812,762
Production
Oil (Bbls)		9,563		7,469
Gas (Mcf)		13,070		8,995
Total (BOE)		11,741		8,968
Total (BOE/d)		32		25
Average prices
Oil (per Bbl)	$	92.76	$	102.50
Gas (per Mcf)		5.45		5.25
Total (per BOE)	$	81.62	$	90.63
Costs and expenses (per BOE)
Lease operating (2)	$	9.91	$	8.06
Severance and production taxes		4.09		5.09
Exploration		-		8.99
Impairment		64.40		530.64
General and administrative		127.32		470.50
Depreciation, depletion, and amortization		46.65		44.19

(1)	Amount includes 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 $958,342 for the fiscal year ended April 30, 2014, compared to $812,762 for the fiscal year ended April 30, 2013. The increase in sales of approximately 18% was attributable primarily to the addition of two wells, offset by our conveyance of certain royalty interests. In the fiscal year ended April 30, 2014, the average price we received for our production was $81.62 per BOE, compared to $90.63 per BOE for the fiscal year ended April 30, 2013. The decrease in average price per BOE was due to the impact of payments made to an unrelated third party for Net Profits Interest. Excluding the effect of the Net Profits Interest adjustment, the average price we received for our production was $90.44 per BOE in 2014.

Net Loss

Net loss for the fiscal year ended April 30, 2014 was $1,030,129 or $(0.02) per basic and diluted share, compared to a net loss of $10,812,694, or $(0.27) per basic and diluted share for the fiscal year ended April 30, 2013. We generated a net loss for the fiscal year ended April 30, 2014 as a result of higher depletion, offset by lower general and administrative expenses, lower impairment expenses and a gain from the conveyance of certain oil and gas properties. We believe that we may incur a net loss for the fiscal year ending April 30, 2015.

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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 $116,347 for the fiscal year ended April 30, 2014, compared to $72,248 for the fiscal year ended April 30, 2013, an increase of 61%. The increase in LOE for the fiscal year ended April 30, 2014 was attributable primarily to increased oil volume produced coupled with non-recurring one time charges.

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

	Year Ended April 30,
	2014		2013
Lease operating expense	$	6.96	$	7.22
Ad valorem taxes		2.95		0.84
Total	$	9.91	$	8.06

Severance and Production Taxes

Our severance and production taxes for the fiscal year ended April 30, 2014 were $48,041 or 4.5% of revenues, compared to $45,668 or 5.6% of revenues for the fiscal year ended April 30, 2013. The increase in severance and production taxes was primarily due to increased production volumes.

Exploration Expense

We recorded $nil of exploration expense for the fiscal year ended April 30, 2014, compared to $80,579 for the fiscal year ended April 30, 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.

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, 2014, our total impairment expense was $756,167, compared to $4,758,812 for the fiscal year ended April 30, 2013. The impairment expense in 2014 included $708,015 impairment of our unproved oil and gas properties related to expiring leased acreage in Sheridan County, Kansas, and $48,152 impairment of our proved oil and gas properties related to capitalized costs in excess of future anticipated cash flow from reserves. In 2013, included in impairment expense was approximately $3,500,000 related to the forfeiture of non-refundable lease deposits, approximately $950,000 related to acreage transferred in connection with the settlement of litigation, and approximately $250,000 recorded in connection with expiring leased acreage. We may be subject to further impairment during the fiscal year ending April 30, 2015.

General and Administrative Expenses

Our general and administrative expenses (“G&A”) decreased to $1,494,869 or 65%, in the fiscal year ended April 30, 2014 from $4,219,407 in the fiscal year ended April 30, 2013. Of the $1,494,869 in G&A costs for fiscal year ended 2014, $553,160 was non-cash related compared to $2,289,537 in non-cash related expenses in the fiscal year ended 2013. The decrease in G&A is primarily due to reduction in share based compensation and reduced professional fees and reduced salaries and benefits.

The following table summarizes G&A:

	Year Ended April 30,
	2014		2013
Share-based compensation	$	553,160	$	2,289,537
Professional fees		315,944		894,423
Salaries and benefits		502,114		643,667
Other		123,651		391,780
Total	$	1,494,869	$	4,219,407

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Depreciation, Depletion and Amortization Expense

Our depreciation, depletion and amortization expense (“DD&A”) was $547,704 in the fiscal year ended April 30, 2014 and $396,319 in the fiscal year ended April 30, 2013. The increase in DD&A is attributable primarily to an 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 11,741 during the year ended April 30, 2014, compared to 8,968, an increase of 2,773 or 31% on a BOE basis when compared to the fiscal year ended April 30, 2013.

Interest Expense, net

Our interest expense, net, was $727,011 for the fiscal year ended April 30, 2014 and $1,556,881 for the fiscal year ended April 30, 2013. This decrease was the result of lower average notes payable balance outstanding during the year ended April 30, 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.

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 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 $395,735 and $125,109 of liquidity at April 30, 2014 and 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, 2014, we had a working capital deficit of $3,648,330, compared to a working capital deficit of $4,167,097 at April 30, 2013. The decrease in working capital deficit for the fiscal year ended April 30, 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:

	2014			2013
Cash flows used in operating activities	$	(897,643	)	$	(1,359,795	)
Cash flows provided by investing activities		1,633,269			611,724
Cash flows provided by (used in) financing activities		(465,000	)		812,554
Net increase in cash and cash equivalents	$	270,626		$	64,483

For fiscal years ended April 30, 2014 and April 30, 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 2014 net cash received of $1,633,269 was primarily comprised of proceeds from the sale of oil and gas properties. In 2013, net cash received from financing activities was $812,554. Proceeds were used to fund operations, drilling activity and debt repayment during the fiscal years ended April 30, 2014 and 2013, respectively.

Operating Activities

For the fiscal year ended April 30, 2014, cash flows used in operating activities decreased by $462,152 to $897,643 from cash flows used in operating activities of $1,359,795 in the fiscal year ended April 30, 2013, primarily due to decreases 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 provided by investing activities was $1,633,269 during the fiscal year ended April 30, 2014 as compared to $611,724 for the fiscal year ended April 30, 2013. The increase in cash provided by investing activities during 2014, relates primarily to proceeds from the sale of oil and gas properties, offset by lower amounts received from our working interest partners and higher distributions in connection with working interest partners during the fiscal year. The majority of our cash flows used in investing activities for the fiscal years ended April 30, 2014 and April 30, 2013 have been used for drilling and acquisitions in Texas and Kansas.

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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 $50,000 from the issuance of convertible notes and repaid a total of $515,000 of outstanding notes in the fiscal year ended April 30, 2014. In comparison, we received $750,000 from the issuance of common stock, $1,200,000 from warrant subscription proceeds, and $125,000 from the issuance of convertible notes, while repaying $1,250,000 of outstanding notes during the fiscal year ended April 30, 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.

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

There were no significant subsequent events.

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	25
Consolidated Balance Sheets as of April 30, 2014 and 2013	26
Consolidated Statements of Operations for the Years Ended April 30, 2014 and 2013	27
Consolidated Statements of Changes in Stockholders’ Deficit for the Years Ended April 30, 2014 and 2013	28
Consolidated Statements of Cash Flows for the Years Ended April 30, 2014 and 2013	29
Notes to Consolidated Financial Statements	31

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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 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’ deficit, and cash flows for the years 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audits 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 years April 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 net losses and used cash in operating activities of $1,030,129 and $897,643, respectively, for the year ended April 30, 2014, and the Company had an accumulated deficit and stockholders’ deficit of $23,091,306 and $2,301,989, respectively, and a working capital deficit of $3,648,330 at April 30, 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

July 31, 2014

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

April 30,

	2014			2013
ASSETS
CURRENT ASSETS:
Cash	$	395,735		$	125,109
Receivables:
Crude oil and natural gas		174,235			128,117
Joint interest and other (net)		47,638			-
Prepaid expenses and other assets		17,283			42,840
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		-			-
Total Other Assets		167,215			167,215
Total Assets	$	1,988,075		$	3,476,528

LIABILITIES AND STOCKHOLDERS’ DEFICIT

CURRENT LIABILITIES:
Accounts payable	$	135,802		$	678,292
Accrued liabilities		135,355			334,464
Salaries and taxes payable		1,212			197,046
Interest payable		315,215			436,890
Derivative liabilities associated with convertible notes		-			63,671
Convertible notes payable, net of unamortized discount		3,695,637			2,752,800
Total Current Liabilities		4,283,221			4,463,163
Convertible notes payable, net of unamortized discount		-			1,330,712
Asset retirement obligation		6,843			-
Total Liabilities		4,290,064			5,793,875
STOCKHOLDERS’ DEFICIT
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
Additional paid in capital		20,716,893			19,699,656
Accumulated deficit		(23,091,306	)		(22,061,177	)
Total Stockholders’ Deficit		(2,301,989	)		(2,317,347	)
Total Liabilities and Stockholders’ Deficit	$	1,988,075		$	3,476,528

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended April 30,
	2014			2013
Revenues:
Oil sales	$	887,087		$	765,548
Gas sales		71,255			47,214
Total Revenues		958,342			812,762

Operating Expenses:
Lease operating		116,347			72,248
Severance and production taxes		48,041			45,668
Depreciation, depletion, and amortization		547,704			396,319
Impairment of oil gas properties		756,167			4,758,812
Exploration		-			80,579
General and administrative		1,494,869			4,219,407
(Gain) on sale of oil and gas properties		(1,232,279	)		-
Total Operating Expenses		1,730,849			9,573,033
Operating Loss		(772,507	)		(8,760,271	)
Other Income (Expense):
Interest expense		(727,011	)		(1,556,881	)
Equity in earnings of unconsolidated affiliates		27,250			(11,671	)
Change in fair value of derivative liability		28,933			23,001
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	)
Gains in connection with forgiveness of debt and accrued liabilities		-			48,021
Net (Loss)	$	(1,030,129	)	$	(10,812,694	)

Net (Loss) Per Share: Basic and Diluted	$	(0.02	)	$	(0.27	)

Weighted Average Shares Outstanding: Basic and Diluted		53,811,242			40,714,604

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

STATEMENT OF CHANGES IN STOCKHOLDERS’ DEFICIT

FOR THE YEARS ENDED APRIL 30, 2014 AND 2013

	Common Stock				Additional Paid in		Accumulated
	Shares		Amount		Capital		Deficit			Total

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,
	2014			2013
Cash flows from operating activities
Net (loss)	$	(1,030,129	)	$	(10,812,694	)
Adjustments to reconcile net loss to net cash used in operating activities
Depreciation and depletion expense		547,704			396,319
Accretion of discount on notes payable		290,638			1,147,742
Exploration expense		-			80,579
Share-based compensation		521,555			2,289,537
Impairment of oil and gas properties		756,167			4,758,812
Equity in earnings of unconsolidated affiliates		-			(89	)
Change in fair value of derivative liabilities		864			(23,001	)
(Gain) Loss in connection with conversion of and settlement of debt and accrued liabilities		(443,412	)		465,046
(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	)
Changes in operating assets and liabilities
Trade accounts receivable		(87,849	)		19,848
Prepaid expenses and other assets		19,650			(22,961	)
Accounts payable		(169,514	)		643,905
Accrued liabilities		(22,308	)		(495,118	)
Bank overdrafts		-			(409,544	)
Salaries and taxes payable		-			193,965
Interest payable		(48,730	)		366,033
Net cash used in operating activities		(897,643	)		(1,359,795	)
Cash flows provided by (used in) investing activities
Acquisitions of oil and gas properties		(134,915	)		(223,945	)
Proceeds received on sale of oil and gas properties		1,897,444			-
Proceeds received from working interest partners		468,000			1,239,629
Distributions to working interest partners		(597,260	)		(416,495	)
Distributions from equity method investees		-			12,535
Net cash provided by investing activities		1,633,269			611,724
Cash flows from financing activities
Partner distributions		-			(12,446	)
Proceeds from the issuance of common stock		-			750,000
Subscription proceeds received - warrants		-			1,200,000
Payments on note issued to seller		-			(1,250,000	)
Proceeds from convertible notes		50,000			125,000
Payments on convertible notes		(515,000	)		-
Net cash provided by (used in) financing activities		(465,000	)		812,554
Net increase in cash		270,626			64,483
Cash
Beginning of year		125,109			60,626
End of year	$	395,735		$	125,109

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended April 30,
	2014		2013
Supplemental Cash Flow Information:
Cash paid for interest	$	485,103	$	33,453
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
Common stock issued for acquisition of WEVCO leases	$	-	$	578,460
Common stock issued for acquisition of Blue Ridge leases	$	-	$	1,827,700
Common stock issued for settlement of WEVCO liabilities	$	-	$	41,040
Common stock issued for settlement of accounts payable	$	158,022	$	123,500
Common stock issued in connection with Debt Conversion	$	126,762	$	1,278,189

See accompanying notes to consolidated financial statements.

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CIRCLE STAR ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APRIL 30, 2014 and 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, 2014, we had cash and cash equivalents of $395,735 and a working capital deficit of $3,648,330. For the year ended April 30, 2014, we incurred a net loss of $1,030,129 and an operating loss of $772,507. Cash used in operations was $897,643.

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.

Use of Estimates

The 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. From time to time, such amounts on deposit are in excess of federally insured limits at April 30, 2014 and 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, 2014 and April 30, 2013 due to their short maturities.

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

The Company derives revenue primarily from the sale of produced natural gas and crude oil. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's interest. Revenues are 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 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 the actual amounts received are recorded when payment is received, or when better information is available.

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Concentration of Credit 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 $nil and $6,596, for the years ended April 30, 2014 and April 30, 2013, respectively.

Asset Retirement Obligations

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.

Asset 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, 2014, the tax years ended April 30, 2013 and April 30, 2012 are still subject to audit.

(Loss) per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net loss per common share is calculated in the same manner, but also considers the impact to net 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, 2014 and April 30, 2013:

	Year Ended April 30,
	2014		2013
Common stock awards issuable pursuant to service contract		-		400,000
Common stock options		-		350,000
Common stock awards		283,333		9,182,167
Convertible notes payable		4,080,000		4,123,095
Common stock warrants		5,250,000		250,000

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.

In 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 eventually 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.

In February 2014, the Company, through its wholly owned subsidiary CSOP, entered into a Participation agreement, whereby the Company became the operator of another well in Trego County, 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 ASC Topic 815, Accounting for Derivative Instruments and Hedging Activities 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 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.

NOTE 4 – FAIR VALUE MEASUREMENTS

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. 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.

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.

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The following tables set forth the liabilities as April 30, 2014 and 2013, which were 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:

Fair Value Measurements at Reporting Date Using

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)

Convertible promissory notes with embedded beneficial conversion feature

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

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 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 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 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 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 were charged to impairment expense.

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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.

NOTE 6—INVESTEES ACCOUNTED FOR UNDER THE EQUITY METHOD

Equity Method Investment

The Company 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 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.

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

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

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NOTE 7—CRUDE OIL AND NATURAL GAS 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. (Note 14)

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.

2014 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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Transfer of Net Profits Interest

During the fiscal year ended April 30, 2014, the Company made distributions of $1,580 to High Plains Oil, LLC (“High Plains”) and $99,774 to an unrelated third party, related to their 10% retained net revenue interest in our wholly-owned subsidiary, JHE Holdings, LLC (“JHE”). Prior to May 9, 2013, this net revenue interest had been owned by High Plains, an entity controlled by S. Jeffrey Johnson, our Chief Executive Officer. On May 9, 2013, High Plains transferred its ownership of the net revenue interest to an unrelated third party. In February 2014, the net revenue interest as held by the unrelated third party increased from 10% to 15%. The increase in the net profits interest was granted in lieu of paying that party $189,000 or 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 8—ASSET RETIREMENT OBLIGATION

For the purpose of determining 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 value of the asset retirement obligation for the periods presented:

	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	$	-

NOTE 9—NOTES PAYABLE

A summary of our notes payable is as follows:

	April 30, 2014			April 30, 2013
(a) Convertible notes payable 12% - December 31, 2014	$	2,310,000		$	2,750,000
Debt Discount		(70,635	)		-
(b) Convertible notes payable 10% - August 15, 2014		-			67,713
Debt Discount		-			(64,913	)
(c) Convertible notes payable 6% - September 14, 2014		1,500,000			-
Debt Discount		(43,728	)		-
Total Current Portion	$	3,695,637		$	2,752,800

(c) Convertible notes payable 6% - September 14, 2014	$	-		$	1,500,000
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 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 were convertible at the option of the holders into common 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. In exchange for these modifications the Company issued the noteholders 250,000 common shares (Note 10). In connection with the issuance of these common shares we recognized a discount to the notes in the amount of $57,500. The discount related to these shares is being amortized over the remaining term of the notes.

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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 common stock at $0.75. The new notes are collateralized by a security interest in the oil and gas properties held by JHE. The Company has maintained the right to 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 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 principal on each note. In connection with the issuance of the 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 debt 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 remaining unamortized portion of the debt discount related to the amended notes amounted to $70,635.

(b)

On August 15, 2012, the Company entered into a convertible note agreement which allowed the Company to borrow up to $555,000. The note was to mature on August 15, 2014. The terms of the note contained a 10% or $55,000 original issuance discount, to be pro-rated based on actual cash drawn in connection with the instrument. The note was 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.

During the fiscal year ended April 30, 2014, 2014, we received net cash proceeds of $50,000 related to borrowings under the terms of the initial note agreement. As of January 31, 2014, we had an outstanding balance of $32,925 under the terms of the note and recorded a discount in the amount of $28,803 to be amortized over the term of the note. The note bore no interest for the 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, the 10% interest charge on all outstanding principal was to accrue immediately. Therefore we accrued $5,000 as 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 recorded a derivative liability totaling $83,185 for the $50,000 draw 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 is re-valued at the end of each fiscal period with changes recorded as charges to our profit and loss. As of April 30, 2014 the entire principal balance of the note had been converted and therefore we recorded a liability of $nil related to the embedded conversion feature and recorded gains of $51,068 during the fiscal year ended April 30, 2014, 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 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 end of the reporting period; and an assumed dividend rate of 0%.

In May, June and July 2013, the Company received conversion notices from the holders of the $555,000 convertible note. The conversion notices indicated the conversion of $82,838 in principal, accrued interest and original issuance discount into 2,296,749 common shares at conversion prices of $0.053, $0.053, $0.023 and $0.023 per share respectively (Note 10).

In December 2013 and January 2014, the Company received conversion notices from the holders of the $555,000 convertible note. The conversion notices indicated the conversion of $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).

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In February, March and April 2014, an additional $32,295 in principal, accrued interest and original issuance discount was converted into 5,526,582 shares of our common stock at prices ranging from $0.0059 to $0.006 per share (Note 10). The balance on the note as of April 30, 2014 was $0 as all principal accrued interest and original issuance discount had been converted as of the end of our fiscal year

(c)

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, 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 was $251,890 and $147,250, respectively.

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

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

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

NOTE 10—SHAREHOLDERS’ EQUITY

Common Stock

The Company has authorized 100,000,000 shares of common stock with a par value of $0.001, of which 72,424,711 and 44,173,404 shares were issued and outstanding as of April 30, 2014 and 2013, respectively.

Activity for the fiscal year ended April 30, 2014 is as follows:

·	On May 7, 2013, we issued 500,000 shares of common stock at $0.0525 per share, the contractual conversion price, in connection with the conversion of $26,250 in principal related to our August 14, 2014, 10% convertible notes payable. (Note 9)

·	On May 23, 2013, we issued 496,429 shares of common stock at $0.0525 per share, the contractual conversion price, in connection with the conversion of $26,062 in principal, original issuance discount and accrued interest on our August 14, 2014, 10% convertible notes payable. (Note 9)

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·	On June 19, 2013, we issued 650,000 shares of common stock at $0.0235 per share, the contractual conversion price, in connection with the conversion of $15,259 in principal related to our August 14, 2014, 10% convertible notes. (Note 9)

·	On July 3, 2013, we issued 650,320 shares of common stock at $0.0235 per share, the contractual conversion price, in connection with the conversion of $15,266 in principal, original issuance discount and accrued interest related to our August 14, 2014, 10% convertible notes payable. (Note 9)

On June 27, 2013, we issued 757,249 shares of common stock to Jeffrey Johnson (“Johnson”) our Chief Executive Officer and President, at $0.08 per share. 504,833 of these shares were issued in connection with the completion of requisite vesting requirements, 252,416 shares were issued as share based compensation related to an allowance for the income tax effect of this vesting and a previous 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.

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Unvested Common Share 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 (250,000) issued at $0.60 and May 1, 2014 (33,000) issued at $2.60 respectively. Unvested share based compensation as of April 30, 2014 amounted to $80,562.

Warrants

Warrant activities for the years ended April 30, 2014 and 2013 are summarized as follows:

	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

During the fiscal year ended April 30, 2014, the Company issued to each of the December 31, 2014, 10% 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 re-pay a minimum of $500,000 in principal on each note.

The table below summarizes warrants to purchase our common shares as of April 30, 2014 and April 30, 2013:

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

Fiscal 2014 Transactions

The assumptions used in the fair value method calculation for the fiscal year ended April 30, 2014 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, 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

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.

Fiscal 2013 Transactions

On 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 11— COMMON STOCK OPTIONS

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

	Shares			Weighted Average Exercise Price
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, 2014 and April 30, 2013 was as follows:

On July 11, 2011, Jonathan Pina our former Chief Financial Officer was granted stock options under the Plan, consisting of options to purchase up to an aggregate of 350,000 shares of the Company’s common stock 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 were to expire, July 11, 2022, July 11, 2023, and July 11, 2024, respectively.

On April 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 $0 and $82,953 as of the fiscal years ended April 30, 2014 and 2013, respectively.

NOTE 12—INCOME TAXES

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

	2014			2013
Current taxes	$	-		$	-
Deferred taxes		(4,558,601	)		(3,879,155	)
Less: valuation allowance		4,558,601			3,879,155
Net income tax provision (benefit)	$	-		$	-

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

	2014			2013
Federal statutory income tax rate		(34.00	%)		(34.00	%)

Permanent differences		1.00	%		3.60	%
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, 2014 and April 30, 2013 are as follows:

	2014			2013
Deferred Tax Assets:
Oil & Gas Properties		447,166			244,719
Stock Compensation		2,364,951			2,172,292
Net Operating Losses		4,356,553			4,072,213
Valuation Allowance		(7,168,670	)		(6,489,224	)
Net Deferred Tax Assets	$	-		$	-

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The Company has approximately a $12,813,000 net operating loss carryforward 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 Company has provided a valuation allowance for the deferred tax asset at April 30, 2014, as the likelihood of the realization of such assets cannot be determined. The valuation allowance increased by $679,446 and $3,879,155 for the years ended April 30, 2014 and 2013, respectively.

NOTE 13—RELATED PARTY TRANSACTIONS

On June 16, 2011, the Company acquired all of the membership interests in JHE, effective as of June 1, 2011 from High Plains, 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. The consideration for JHE included, among other things, a 10% net profits interest in JHE to be retained by High Plains. 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.

NOTE 14—COMMITMENTS AND 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 expired on January 31, 2014. We currently lease our office space on a month to month basis and may terminate the lease with two months written notice.

Litigation

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 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 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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Convertible Notes

Jonathan G. Pina

NOTE 15—SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The aggregate amount of capitalized costs related to oil and gas property and the aggregate amount of related accumulated depletion and impairment as of April 30, 2014 and 2013 are as follows:

	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

The 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

None.

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.

As 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.

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, 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 May 2014, we engaged a third party consulting firm to handle our day to day accounting functions including but not limited to the recording of accounts payable and cash disbursements. We believe that the utilization of this third party will remediate our weakness related to lack of segregation of duties as cited above. .

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 the date 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	49	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, 2014, except for the following reports:

Name

Number of

Late Reports

CIRCLE STAR ENERGY CORP. 10-K