RenovaCare, Inc. - Quarter Report: 2012 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

Or

¨ 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: 000-30156

JANUS RESOURCES, INC.

(Exact name of registrant as specified in its charter)

800-755-5815

(Registrant’s telephone number, including area code)

10180 – 101 Street, Suite 3400, Edmonton, AB, Canada t5j3s4

(Former name, former address and former fiscal year if changed since last report)

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

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

As of August 17, 2012, the registrant had 63,075,122 shares of its common stock, par value $0.00001 per share, issued and outstanding.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

JANUS RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

June 30, 2012 and December 31, 2011

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

JANUS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

JANUS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

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

JANUS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

For the six months ended June 30, 2012 and the year ended December 31, 2011

(Unaudited)

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

JANUS RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the six months ended June 30, 2012 and 2011

(unaudited)

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

JANUS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Nature and Continuance of Operations

Janus Resources, Inc. (formerly Entheos Technologies, Inc.) (the “Company”, “we”, “us”, and “our”) is in the business of location, acquisition, exploration and, if warranted, development of both mineral exploration properties and oil and gas properties. The Company pursues oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise. Currently, its interests consist of non-operating, minority working interests in oil and gas properties. On June 8, 2011, the Company completed the acquisition of the Fostung tungsten property, located in Foster Township, Sudbury, Ontario, Canada.

The Company’s general business strategy is to acquire mineral properties and oil and gas properties either directly or through the acquisition of operating entities. Its continued operations and the recoverability of property costs are dependent upon the existence of economically recoverable mineral and oil and gas reserves, the confirmation of its interest in the underlying properties, its ability to obtain necessary financing to complete development, and future profitable production.

Effective January 5, 2011, the Company changed its name from “Entheos Technologies, Inc.” to “Janus Resources, Inc.” so as to more fully reflect the Company’s operations.

The Company has recently incurred net operating losses and operating cash flow deficits. The Company’s accumulated deficit is $4,408,236 at June 30, 2012. It may continue to incur losses from operations and operating cash flow deficits in the future. Management believes that the Company’s cash and cash equivalent balances, anticipated cash flows from operations and other external sources of credit will be sufficient to meet its cash requirements through December 2012 if not further. The future of the Company after December 2012 will depend in large part on its ability to successfully generate cash flows from operations and raise capital from external sources to fund operations.

2. Significant Accounting Policies

Basis of Presentation and Principles of Accounting

The interim consolidated financial statements included herein have been prepared by the Company, without audit, in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) pursuant to Part 210 of Regulation S-X. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have been condensed or omitted pursuant to such SEC rules and regulations, although the Company believes that the disclosures included are adequate to make the information presented not misleading.

In management’s opinion, the unaudited consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of our financial position, results of operations, and cash flows on a basis consistent with that of our prior audited consolidated financial statements. The Company has evaluated information about subsequent events that became available to them through the date the financial statements were issued. This information relates to events, transactions or changes in circumstances that would require us to adjust the amounts reported in the financial statements or to disclose information about those events, transactions or changes in circumstances. However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year. Therefore, these financial statements should be read in conjunction with the Company’s audited consolidated financial statements including the notes thereto for the year ended December 31, 2011 which may be found under the Company’s profile on EDGAR.

The accounting policies followed by the Company are set out in note 2 to the audited consolidated financial statements for the year ended December 31, 2011 and have been consistently followed in the preparation of these consolidated interim financial statements.

Principles of Consolidation

These interim consolidated financial statements have been prepared in accordance with US GAAP and include the accounts of the Company and its wholly-owned subsidiaries, Fostung Resources, Limited (“Fostung”) and Entheos Energy, Inc. (“Entheos”). Collectively, they are referred to herein as “the Company.” All significant intercompany transactions and balances have been eliminated. Fostung was formed on incorporated on May 10, 2011 in Ontario Canada. Entheos was incorporated under the laws of the State of Nevada on October 5, 2000.

The Company accounts for its undivided interest in oil and gas properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements.

Applicable Accounting Guidance

Any reference in these notes to applicable accounting guidance is meant to refer to the authoritative non-governmental United States GAAP as found in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”).

Accounting Estimates

The preparation of interim consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of management estimates include the determination of impairment of mineral properties, oil and gas properties and equipment, useful lives for amortization, valuation allowances for future income tax assets and asset retirement obligations. Actual results, as determined by future events, may differ from these estimates. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. The more significant reporting areas impacted by management’s judgments and estimates are accruals related to oil and gas sales and expenses; estimates used in the impairment of oil and gas properties; and the estimated future timing and cost of asset retirement obligations.

The carrying values of oil and gas properties are particularly susceptible to change in the near term. Changes in the future estimated oil and gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.

Mineral Properties

The Company has concluded that mineral rights meet the definition of tangible assets. Accordingly, the Company accounts for its mineral properties on a cost basis whereby all direct costs, net of pre-production revenue, relative to the acquisition of the properties are capitalized. All sales and option proceeds received are first credited against the costs of the related property, with any excess credited to earnings. Once commercial production has commenced, the net costs of the applicable property will be charged to operations using the unit-of-production method based on estimated proven and probable recoverable reserves. The net costs related to abandoned properties are charged to operations.

Costs of exploring, carrying and retaining unproven properties are charged to operations as incurred until such time that proven reserves are discovered. From that time forward, the Company will capitalize all costs to the extent that future cash flow from mineral reserves equals or exceeds the costs deferred. The deferred costs will be amortized over the recoverable reserves when a property reaches commercial production. As at June 30, 2012 and December 31, 2011, the Company did not have proven reserves. Exploration activities conducted jointly with others are reflected at the Company's proportionate interest in such activities.

Full Cost Method of Accounting for Oil and Gas Properties

The Company has elected to utilize the full cost method of accounting for its oil and gas activities. In accordance with the full cost method of accounting, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs and related asset retirement costs are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves once proved reserves are determined to exist. The Company has not yet obtained reserve reports. Management is assessing production data to determine the feasibility of obtaining reserves studies. At June 30, 2012 and December 31, 2011, there were no capitalized costs subject to amortization.

Oil and gas properties without estimated proved reserves are not amortized until proved reserves associated with the properties can be determined or until impairment occurs. As a result of management’s impairment analysis, the Company recorded an impairment loss of $481 and $2,604 during the six month periods ended June 30, 2012 and 2011, respectively. The impairment loss amounted to $149 and $1,301 for the three months ended June 30, 2012 and 2011, respectively. The impairment is similar to amortization and therefore is not added to the costs of properties being amortized. See “Note 6. Fair Value Measurement” for further information.

Sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. The Company has not sold any oil and gas properties.

Asset Retirement Obligation

The Company records the fair value of the liability for closure and removal costs associated with the legal obligations upon retirement or removal of any tangible long-lived assets by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement obligation is included in oil and gas properties in the balance sheets. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method. Asset retirement obligations amounted to $56,784 and $55,316 at June 30, 2012 and December 31, 2011, respectively.

Impairment of Long-Lived Assets

The Company reviews and evaluates its long-lived assets for impairment at each balance sheet date and documents such impairment testing. The tests include an evaluation of the assets and events or changes in circumstances that would indicate that the related carrying amounts may not be recoverable.

Oil and gas properties are subject to a “ceiling test” which basically limits capitalized costs to the sum of the estimated future net revenues from proved reserves, discounted at 10% per annum to present value, based on current economic and operating conditions, adjusted for related income tax effects.

Mineral properties in the exploration stage are monitored for impairment based on factors such as the Company’s continued right to explore the area, exploration reports, assays, technical reports, drill results and the Company’s continued plans to fund exploration programs on the property, whether sufficient work has been performed to indicate that the carrying amount of the mineral property cost carried forward as an asset will not be fully recovered, even though a viable mine has been discovered.

The tests for long-lived assets in the exploration, development or producing stage that would have a value beyond proven and probable reserves would be monitored for impairment based on factors such as current market value of the mineral property and results of exploration, future asset utilization, business climate, mineral prices and future undiscounted cash flows expected to result from the use of the related assets. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset, including evaluating its reserves beyond proven and probable amounts.

The Company’s policy is to record an impairment loss in the period when it is determined that the carrying amount of the asset may not be recoverable either due to impairment or by abandonment of the property. The impairment loss is calculated as the amount by which the carrying amount of the asset exceeds its fair value. While the Company incurred losses from operations, these losses have not been in excess of planned expenditures on the specific mineral properties in order to ultimately realize their value.

Warrant Liability Derivative

The Company evaluates financial instruments for freestanding or embedded derivatives. As part of the July 2008 financing, the Company issued warrants that did not meet the specific conditions for equity classification. During the term of the warrants, the Company classified the fair value of the warrants as a liability, with changes in fair value recorded as income (loss). The fair value of the warrants were recorded as a liability until the warrants expired on December 31, 2011.

Oil and Gas Revenue Recognition

The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations, distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 45 days following the month of production. Therefore, the Company may make accruals for revenues and accounts receivable based on estimates of its share of production. Since the settlement process may take 30 to 60 days following the month of actual production, its financial results may include estimates of production and revenues for the related time period. The Company will record any differences between the actual amounts ultimately received and the original estimates in the period they become finalized.

Earnings (Loss) Per Share

The computation of basic net income (loss) per common share is based on the weighted average number of shares that were outstanding during the year. Diluted earnings per share is computed by adjusting the weighted average number of common shares for the impact of dilutive securities. See “Note 3. Earnings (Loss) Per Share” for further discussion.

Foreign Currency Translation

Transactions and account balances originally stated in currencies other than the U.S dollar have been translated into U.S. dollars as follows:

Exchange gains and losses are recorded in operations in the period in which they occur, except for exchange gains and losses related to translation of monetary assets and liabilities associated with mineral properties, which are deferred and included in mineral properties.

Comprehensive income

Comprehensive loss is comprised of net loss and foreign currency translation adjustments for the periods presented.

Related Party Transactions

A related party is generally defined as (i) any person who holds 10% or more of the Company’s securities and their immediate families, (ii) the Company’s management, (iii) someone who directly or indirectly controls, is controlled by or is under common control with the Company, or (iv) anyone who can significantly influence the financial and operating decisions of the Company. A transaction is considered to be a related party transaction when there is a transfer of resources or obligations between related parties. See “Note 9. Related Party Transactions” for further discussion.

Concentration of Risk

Financial instruments that subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, and accounts receivable. The Company occasionally has cash deposits in excess of federally insured limits. The Company has not experienced any losses related to these balances, and management believes its credit risk to be minimal. Accounts receivable are with the operators of the oil wells in which the Company participates. Given the close working relationship between the operators and the Company, management believes its credit risk is minimal.

Fair Values of Financial Instruments

The Company measures certain financial assets and liabilities at fair value based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in on orderly transaction between market participants. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of maturity of the instruments. See Note 6 for further discussion on fair value of financial instruments.

Recently Issued Accounting Standards Updates

Accounting Standards Update No. 2011-04: Fair value measurements update 2011-04

In May 2011, the FASB issued an update to the authoritative guidance related to fair value measurements as a result of the FASB and the IASB working together to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with US GAAP and International Financial Reporting Standards (“IFRS”). The amendments will add new disclosures, with a particular focus on Level 3 measurements. The objective of these amendments is to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments in this update are to be applied prospectively. The amendments were effective during interim and annual periods beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the consolidated financial statements.

Accounting Standards Update No. 2011-05: Presentation of Comprehensive Income 2011-05

In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (ASU 2011-05). Under ASU 2011-05, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Under both options, an entity will be required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In December 2011, the FASB issued ASU 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" (ASU 2011-12), which deferred the requirement to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income while the FASB further deliberates this aspect of the proposal. The amendments contained in ASU 2011-05 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments also do not affect how earnings per share is calculated or presented. ASU 2011-05, as amended by ASU 2011-12, was effective for us on January 1, 2012. The adoption of this guidance did not have a material impact on the consolidated financial statements.

3. Earnings (Loss) Per Share (EPS)

Following is the computation of basic and diluted net income (loss) per share for the three and six month periods ended June 30, 2012 and 2011:

Potentially dilutive shares of common stock for the three and six month periods ended June 30, 2011, consisted of 12,900,000 shares of common stock issuable under warrants (none for the three and six month periods ended June 30, 2012).

4. Oil and Gas Properties

The aggregate amount of capitalized costs relating to crude oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at June 30, 2012 and December 31, 2011 were:

The Company has not obtained reserve studies with estimated proved reserves. Management is assessing production data to determine the feasibility of obtaining reserves studies. Therefore, at June 30, 2012 and December 31, 2011, there were no proved properties subject to amortization.

Properties which are not being amortized are assessed quarterly, on a property-by-property basis, to determine whether they are recorded at the lower of cost or fair market value. As a result of this analysis and lack of reserve studies, the Company recorded an impairment loss of $481 and $2,604 for the six month periods ended June 30, 2012 and 2011, respectively. The impairment recognized was to bring the carrying costs of the wells to their anticipated salvage value since most of the wells are approaching end of life unless additional capital investments are made. The impairment is similar to amortization and therefore is not added to the cost of properties being amortized.

5. Mineral Properties and Exploration Expenses

Foster Township, Sudbury, Ontario, Canada - Fostung Tungsten Property

6. Fair Value Measurement

Fair value is defined within the accounting rules as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1. Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;

Level 2. Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

Level 3. Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s Balance Sheet. The following methods and assumptions were used to estimate the fair values:

Oil and Gas Properties. Oil and gas properties which are not being amortized are assessed quarterly, on a property-by-property basis, to determine whether they are recorded at the lower of cost or fair market value. In determining whether such costs should be impaired, the Company evaluates historical experience, current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. Given the unobservable nature of the inputs, the measurement of fair value is deemed to use Level 3 inputs. The impairment is included in operating costs. See Note 4 for a summary of changes in capitalized costs of oil and gas properties.

Asset Retirement Obligation. The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations .” The income valuation technique is utilized by the Company to determine the fair value of the liability at the point of inception by taking into account 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates by management; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

The following table presents the Company’s financial assets and liabilities, which were accounted for at fair value on a non-recurring basis as of June 30, 2012, by level within the fair value hierarchy.

7. Stockholders’ Equity

The Company has an active stock option plan that provides shares available for option grants to employees, directors and others. A total of 20,000,000 shares of the Company’s common stock have been reserved for award under the stock option plan, of which 20,000,000 were available for future issuance as of June 30, 2012. Options granted under the Company’s option plan generally vest over five years or as otherwise determined by the Board of Directors, have exercise prices equal to the fair market value of the common stock on the date of grant, and expire no later than ten years after the date of grant.

During the six month period ended June 30, 2012 and the year ended December 31, 2011, the Company did not grant any stock option awards.

8. Commitments and Contingencies

As part of the acquisition of the Fostung tungsten property, located in Foster Township, Sudbury Mining Division, Ontario, Canada, the Company will pay to Breakwater Resources Ltd. (i) a Production Bonus in the amount of CAD $500,000 within thirty (30) business days following the commencement of commercial production from the property and (ii) a 1% Net Smelter Return royalty.

9. Related Party Transactions

On January 12, 2012, Mr. Cacace resigned from the positions of President, Chief Executive Officer, Chief Financial Officer and Director of the Company and Mr. Derek Cooper was appointed to the positions of President, Chief Executive Officer, Chief Financial Officer and Director of the Company. On June 18, 2012, Mr. Derek Cooper resigned as the Company’s President, Chief Executive Officer, Chief Financial Officer and Director. Effective as of June 19, 2012, Mr. Joseph Sierchio, one of the Company’s directors, was appointed as its Acting Interim President and Chief Executive Officer; and effective as of June 27, 2012, Ms. Janet Bien was appointed as the Company’s Chief Financial Officer.

For the three and six month periods ended June 30, 2012, fees of $7,500 (2011 - $9,000) and $16,689 (2011 - $18,000) were paid or are due to officers of the Company.

For the three and six month periods ended June 30, 2012, directors fees of $0 (2011 - $12,000 and $0 (2011 - $24,000) were paid to non-officer directors of the Company.

For the three and six month periods ended June 30, 2012, legal fees of $32,222 (2011- $18,375) and $44,966 (2011 - $34,017) were paid or are due to a company controlled by our attorney, Mr. Sierchio. Included in accounts payable - related parties at June 30, 2012 is $27,383 (December 31, 2011 - $7,850) for legal fees.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and related notes appearing elsewhere in this Quarterly Report filed on Form 10-Q. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under the heading “Risk Factors and Uncertainties” in our Form 10-K filed with the SEC on March 29, 2012, and elsewhere in this report.

This discussion and analysis should be read in conjunction with the accompanying unaudited interim consolidated financial statements and related notes. The discussion and analysis of the financial condition and results of operations are based upon the unaudited interim consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires Janus to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an on-going basis Janus reviews its estimates and assumptions. The estimates were based on historical experience and other assumptions that Janus believes to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but Janus does not believe such differences will materially affect our financial position or results of operations. Critical accounting policies, the policies Janus believes are most important to the presentation of its financial statements and require the most difficult, subjective and complex judgments, are outlined below in “Critical Accounting Policies,” and have not changed significantly.

Cautionary Note Regarding Forward-Looking Statements

In addition, certain statements made in this report may constitute “forward-looking statements”. These forward-looking statements involve known or unknown risks, uncertainties and other factors that may cause the actual results, performance, or achievements of Janus to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Except for historical information, the matters set forth herein, which are forward-looking statements, involve certain risks and uncertainties that could cause actual results to differ. Potential risks and uncertainties include, but are not limited to, unexpected changes in business and economic conditions; significant increases or decreases in commodity prices; changes in interest and currency exchange rates; unanticipated grade changes; metallurgy, processing, access, availability of materials, equipment, supplies and water; determination of reserves; results of current and future exploration activities; results of pending and future feasibility studies; joint venture relationships; political or economic instability, either globally or in the countries in which we operate; local and community impacts and issues; timing of receipt of government approvals; accidents and labor disputes; environmental costs and risks; competitive factors, including competition for property acquisitions; and availability of external financing at reasonable rates or at all.

Forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “intends,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential,” “continues” or the negative of these terms or other comparable terminology. Although Janus believes that the expectations reflected in the forward-looking statements contained herein are reasonable, it cannot guarantee future results, levels of activity, performance or achievements. Forward-looking statements are made based on management’s beliefs, estimates, and opinions on the date the statements are made, and Janus undertakes no obligation to update such forward-looking statements if these beliefs, estimates, and opinions should change, except as required by law.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following is a description of the meanings of some of the natural gas and oil industry terms used in this filing:

“Bbl” means a barrel or barrels of oil.

“BOE” means barrels of oil equivalent.

“Btu” means British thermal unit, which means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion” means the installation of permanent equipment for the production of natural gas or oil.

“Condensate” means hydrocarbons naturally occurring in the gaseous phase in a reservoir that condense to become a liquid at the surface due to the change in pressure and temperature.

“Crude” means unrefined liquid petroleum.

“Gross acres” or “gross wells” refer to the total acres or wells, as the case may be, in which a working interest is owned.

“Mcf” means thousand cubic feet of natural gas. We have assumed that 1Mcf = 1 MMBtu for our calculations.

“MMBtu” means one million Btus.

“Operator” refers to the individual or company responsible for the exploration, development and production of an oil or gas well or lease.

“Proved developed oil and gas reserves” refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and 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 should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

“Proved oil and gas reserves” means the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves” (b) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

“Proven properties” refers to properties containing proved reserves.

“Proved undeveloped reserves” refers to 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 recompletion. 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 can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“Recompletion” means, after the initial completion of the well, the actions and techniques of re-entering the well and redoing or repairing the original completion in order to restore the well’s productivity.

“Shut-in” means a well which is capable of producing but is not presently producing.

“Unproven properties” refers to properties containing no proved reserves.

“Working interest” refers to the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

“Workover” means operations on a producing well to restore or increase production.

GLOSSARY OF CERTAIN MINERAL EXPLORATION TERMS

The following is a description of the meanings of some mineral exploration terms used in this filing:

“Net Smelter Return” (“NSR”) royalties are based on the value of production or net proceeds received by the operator from a smelter or refinery. These proceeds are usually subject to deductions or charges for transportation, insurance, smelting and refining costs as set out in the royalty agreement. For gold royalties, the deductions are generally minimal while for base metal projects, the deductions can be much more substantial. This type of royalty provides cash flow that is free of any operating or capital costs and environmental liabilities. A smaller percentage NSR in a project can effectively equate to the economic value of a larger percentage profit or working interest in the same project.

Overview

Company Overview

We are in the business of location, acquisition, exploration and, if warranted, development of both mineral exploration properties and oil and gas properties. We pursue oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise. Currently, its interests consist of non-operating, minority working interests in oil and gas properties.

Recent Changes in Management

On June 18, 2012, Mr. Derek Cooper resigned as our President, Chief Executive Officer, Chief Financial Officer and Director. Effective as of June 19, 2012, Mr. Joseph Sierchio, one of our directors, was appointed as our Acting Interim President and Chief Executive Officer and effective as of June 27, 2012, Ms. Janet Bien was appointed as our Chief Financial Officer.

Mineral Properties

We are currently concentrating our mineral property exploration activities in Canada and our oil and gas property exploration activities in the United States of America (the “USA”). Our strategy is to concentrate our investigations into: (i) existing operations where an infrastructure already exists; (ii) properties presently being developed and/or in advanced stages of exploration which have potential for additional discoveries; and (iii) grass-roots exploration opportunities. We are also examining data relating to the potential acquisition of other mineral exploration properties.

On June 8, 2011, we completed the acquisition of the Fostung tungsten property, located in Foster Township, Sudbury, Ontario, Canada. Our mineral property is in the exploration stage only and is without a known body of mineral reserves. Development of the property will follow only if satisfactory exploration results are obtained. Mineral exploration and development involves a high degree of risk and few properties that are explored are ultimately developed into producing mines. There is no assurance that our mineral exploration and development activities will result in any discoveries of commercially viable bodies of mineralization reserves. The long-term profitability of our operations will be, in part, directly related to the cost and success of our exploration programs, which may be affected by a number of factors.

Foster Township, Sudbury, Ontario, Canada – Fostung Tungsten Property

A production bonus in the amount of CAD $500,000 is payable to Breakwater Resources Ltd. by us within thirty business days following the commencement of commercial production from the property. A 1% net smelter return royalty on the property is also payable to Breakwater Resources Ltd. by us. No capitalized costs have been amortized as of June 30, 2012. We did not incur any impairment of these capitalized costs through June 30, 2012.

Oil and Gas Properties

We pursue oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise. Our interests consist of non-operating, minority working interests in properties in La Salle County, Fayette County, Lee County and Frio County, Texas.

The leases for these properties are maintained and operated by Leexus Oil LLC and Millennium Petro-Physics; there are no obligations to further explore or develop lands in the lease areas to maintain the leases. The operators of the leases are not affiliated with Janus or any of its directors or major shareholders. We are not aware of any relationships or affiliations between or among any of our leasehold partners and the lease operators.

We plan to grow our oil and gas operations by acquiring minority, non-operating, working interests in both currently producing wells and also by participating in workover and/or re-entry projects on previously producing proved assets or wells. These assets will be pursued to offset the natural decline in our current production as well as provide growth in our asset portfolio over time. Assets for acquisition will be identified through our operators, managements’ contacts in the industry as well as through the Petroleum Listing Service (“PLS”).

Assets will be evaluated by management as well as by third party independent consulting engineers and geologists, having experience in the geographical areas in which the prospects are located, engaged by us on an as needed basis. The industry professionals to be utilized by us will be contractors and will be compensated as such utilizing finder's fee agreements and consulting agreements.

Acquisition of Oil & Gas Properties

The following table sets forth a summary of our current oil and gas interests:

Capitalized costs associated with the property are as follows:

Geologic Background

Escondido Formation

The Escondido formation, where Cooke #6 is located, is a regional producer spanning several counties in South Texas. There are many Escondido oil and gas fields which have produced anywhere from 600,000 to 3,100,000 barrels of oil and the gas fields have produced up to 18 BCF of gas. However, this is no assurance that Cooke #6 will produce or continue to produce any oil and gas.

Austin Chalk Formation

Giddings is a main producing field of the Austin Chalk formation consisting of fractured carbonate, which is where our Onnie Ray #1 and Stahl #1 wells are located. This formation covers central Texas, parts of Mexico and northwest Louisiana. The Austin Chalk in central Texas has been and continues to be explored and developed for its oil and gas potential by companies such as Anadarko Petroleum Corporation, Chesapeake Energy Corporation, and Exxon Mobil Corporation. In March 2011, Leexus Oil LLC, the operator, who also owns a working interest in the Onnie Ray #1 H well, provided us with a plan for the re-completion of the well. We have decided not to participate in the proposed re-completion of the Onnie Ray #1H well. This decision may delay our cost recovery from this well even if the recompletion results in increased production.

Haile #1 and Pearce #1 wells are located within the Pearsall Austin Chalk field which is south west of the Giddings field and is also a significant historic producer. The Pearsall field has been and continues to be explored and developed much like the Giddings fields to the North.

At the time of acquisition, the Reeves #1H (Haile) well was not supported by actual production nor were there defined engineering reserve studies. The well was being re-completed to a zone that was previously productive. Once the recompletion efforts were final and the well did not support production, an exploratory drilling program was started in early 2009 to complete a new unproven upper zone. The new upper zone recompletion also resulted in no oil or gas production and the well was shut-in August 2009. Management has impaired the well to the extent of anticipated salvage value of the equipment. In January 2011, Leexus Oil LLC, the operator who also owns a working interest in the well provided us with a plan for the re-completion of the well. We have decided not to participate in the proposed re-completion of the Reeves #1H (Haile) well.

Production and Reserve Estimate Status

Neither we, nor our partners, Leexus Oil LLC and Millennium Petro-Physics (collectively, the “Partners”), have conducted any reserve studies and after further assessment of the matter, neither we nor the Partners believe it to be commercially reasonable, based on production to date, to undertake the expense of conducting a reserve study. Additionally, we maintain only a minority working interest in each of the properties, which are actively maintained by the Partners; accordingly, we are not in a position to unilaterally conduct reserve studies on these properties and no reserve studies have been provided to us by the Partners.

Results of Operations

Three and six month period ended June 30, 2012 (Fiscal 2012) versus three and six month period ended June 30, 2011 (Fiscal 2011).

Revenues- Oil production during the three month period ended June 30, 2012 and 2011 totaled 27 (2011 - 82) barrels and generated revenues of $2,719 (2011 - $7,886). The 66% decline in production was offset slightly by a 4% increase in the average price per barrel. Total oil and gas revenues decreased 66% in 2012 compared to 2011 due to the natural decline of the wells. Average daily production on an equivalent basis was 0.48 BOE in 2012 compared to 1.28 BOE in 2011.

Oil production during the six month period ended June 30, 2012 and 2011 totaled 86 (2011 - 148) barrels and generated revenues of $8,471 (2011 - $13,453). The 42% decline in production was offset slightly by an 8% increase in the average price per barrel. Total oil and gas revenues decreased 37% in 2012 compared to 2011 due to the natural decline of the wells. Average daily production on an equivalent basis was 0.60 BOE in 2012 compared to 1.23 BOE in 2011.

Gas production during three month period ended June 30, 2012 and 2011 totaled 95 (2011 - 202) Mcf and generated $743 (2011 - $2,194) in revenue. The 66% decline in production was accompanied by a 28% decline in average gas prices.

Gas production during six month period ended June 30, 2012 and 2011 totaled 130 (2011 - 443) Mcf and generated $1,044 (2011 - $4,260) in revenue. The 71% decline in production was accompanied by a 16% decline in average gas prices.

Lease Operating Expenses - Lease operating expenses for the three months ended June 30, 2012 decreased 29% to $3,974 (2011 - $5,590) due to decreased production. Lease operating expenses consist of day-to-day operational expenses for production of oil and gas and maintenance and repair expenses for the wells and properties.

Lease operating expenses for the six months ended June 30, 2012 decreased 16% to $8,999 (2011 - $10,761) due to decreased production. Lease operating expenses consist of day-to-day operational expenses for production of oil and gas and maintenance and repair expenses for the wells and properties.

Impairment of Oil and Gas Properties - Depreciation, depletion, amortization and impairment of oil and gas properties decreased 88% to $150 (2011 - $1,301) during the three month period ended June 30, 2012, and they decreased 82% to $481 (2011 - $2,604) during the six month period ended June 30, 2012, due to the carrying value of our wells approaching salvage value.

Expenses - Our general and administrative expenses consist primarily of personnel costs, legal costs, investor relations costs, accounting costs and other professional and administrative costs. For the three months ended June 30, 2012 we recorded General and Administrative expenses of $69,131 (2011- $132,056). This amount includes, professional fees - accounting of $12,954 (2011 - $41,560); legal $32,222 (2011 - $18,375); public relations, office, travel, filing, transfer and regulatory fees of $16,455 (2011 - $27,432); management, director and consulting fees of $7,500, $0 and $0 (2011 - $9,000, $12,000 and $23,689) respectively.

Our general and administrative expenses consist primarily of personnel costs, legal costs, investor relations costs, accounting costs and other professional and administrative costs. For the six months ended June 30, 2012 we recorded General and Administrative expenses of $149,942 (2011- $280,127). This amount includes, professional fees - accounting of $55,984 (2011 - $93,901); legal $44,966 (2011 - $39,084); public relations, office, travel, filing, transfer and regulatory fees of $27,303 (2011 - $59,690); management, director and consulting fees of $16,689, $0 and $5,000 (2011 - $18,000, $24,000 and $45,452) respectively.

Exploration Expenditures - Exploration expenses on the Fostung property are charged to operations as they are incurred. For the three and six month periods ended June 30, 2012, we recorded exploration expenses of $8,146 (2011 - $101,935) and $11,284 (2011 - $101,935).

Change in Fair Value of Warrant Liability - As a result of adjusting the warrant liability to fair value, we recorded a non-cash gain of $0 (2011 - $2,994,812) and $0 (2011 – $3,000,648) relating to the Warrants for the three and six month period ended June 30, 2012, respectively.

Oil and Gas Interests

We utilize the full cost method of accounting for our oil and gas activities. In accordance with the full cost method of accounting, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized. Net capitalized costs associated with oil and gas properties as of June 30, 2012 and December 31, 2011 is summarized as follows:

At the time of acquisition, Haile #1 was being recompleted to a zone that was previously productive. Once the recompletion efforts were final and the well did not support production, an exploratory drilling program was started in early 2009 to complete a new unproven upper zone. The new upper zone completion also resulted in no oil or gas production and the well was shut-in during August 2009. In accordance with our accounting policies, we assessed this well, at December 31, 2009, to determine whether the well was recorded at the lower of cost or fair market value. Upon completion of our assessment, we impaired the well to the extent of anticipated salvage value of the equipment and recorded an asset retirement obligation to accrue for estimated closure costs. In January 2011, Leexus Oil LLC, the operator who also owns a working interest in the well provided to us with a plan for the re-completion of the well. We have decided not to participate in the proposed re-completion of the Reeves #1H (Haile) well.

In March 2011, Leexus Oil LLC, the operator, who also owns a working interest in the Onnie Ray #1H well provided us with a plan for the re-completion of the well. We have decided not to participate in the proposed re-completion of the Onnie Ray #1H well.

Costs incurred in oil and gas property acquisition, exploration and development activities for the three and six months ended June 30, 2012, and the year ended December 31, 2011, were:

Asset Retirement Obligation

The following table summarizes the activity for the Company’s asset retirement obligations:

Production and Revenue

Our production consists of natural gas and crude that is marketed by the well site Operators. We sell our crude oil and condensate production at or near the well-site, although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline and is typically committed to arrangements having a term of one year or less. We have not engaged in crude oil hedging or trading activities. We have not engaged in natural gas hedging or futures trading, nor do we have any long term contracts to sell our production.

Sales of crude oil totaled $2,719 and $7,886 for the three months ended June 30, 2012 and 2011, respectively, which represents 95% and 73% of our total oil and gas revenues for the three months ended June 30, 2012 and 2011, respectively. Sales of natural gas totaled $743 and $2,194 for the three month period ended June 30, 2012 and 2011, respectively.

Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil (“NYMEX-WTI”). The average crude oil price per Bbl received by us for the three month period ended June 30, 2012 and 2011was $97.33 and $84.22, respectively.

Natural gas and natural gas liquids prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our natural gas. Average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us for the three month period ended June 30, 2012 and 2011 was $8.50 and $8.55, respectively.

The table below shows the results of operation for the Company’s oil and gas producing activities for the three and six month period ended June 30, 2012 and 2011. All production is within the continental United States.

Mineral Property Interests

We have concluded that mineral rights meet the definition of tangible assets. Accordingly, we account for our mineral properties on a cost basis whereby all direct costs, net of pre-production revenue, relative to the acquisition of the properties are capitalized. All sales and option proceeds received are first credited against the costs of the related property, with any excess credited to earnings. Once commercial production has commenced, the net costs of the applicable property will be charged to operations using the unit-of-production method based on estimated proven and probable recoverable reserves. The net costs related to abandoned properties are charged to operations.

Costs of exploring, carrying and retaining unproven properties are charged to operations as incurred until such time that proven reserves are discovered. From that time forward, we will capitalize all costs to the extent that future cash flow from mineral reserves equals or exceeds the costs deferred. The deferred costs will be amortized over the recoverable reserves when a property reaches commercial production. At June 30, 2012, we did not have proven reserves. Exploration activities conducted jointly with others are reflected at our proportionate interest in such activities.

Liquidity and Capital Resources

We currently finance our activities primarily by the private placement of securities. There is no assurance that equity funding will be accessible to us at the times and in the amounts required to fund our activities. There are many conditions beyond our control which have a direct bearing on the level of investor interest in the purchase of Company securities. We may also attempt to generate additional working capital through the operation, development, sale or possible joint venture development of its properties; however, there is no assurance that any such activity will generate funds that will be available for operations. Failure to obtain such additional financing may result in a reduction of our interest in certain properties or an actual foreclosure of our interest. Debt financing has not been used to fund our property acquisitions and exploration activities, and we have no current plans to use debt financing. We do not have “standby” credit facilities, or off-balance sheet arrangements and it does not use hedges or other financial derivatives. We have no agreements or understandings with any person as to additional financing.

We began 2012 with cash and cash equivalents of $787,771. At June 30, 2012, we had cash of $602,657. Total liabilities as of June 30, 2012 were $105,680 (December 31, 2011 - $129,009).

Our unaudited interim consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America and applicable to a going concern which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. Our continuation as a going concern is dependent upon the continued financial support of its shareholders, our ability to obtain necessary equity financing to continue operations, confirmation of our interest in the underlying properties, the attainment of profitable operations and/or realizing proceeds from the sale of one or more of the properties. As discussed in “Note 1” to the consolidated financial statements, we have incurred recurring operating losses since inception. As at June 30, 2012, we have an accumulated deficit of $4,408,236 and working capital of $565,692, which management believes is sufficient to fund operations through at least the next twelve months, however we intend to raise additional equity (presumably through equity offerings and/or debt borrowing) as the opportunity presents itself.

Our mineral exploration properties have not commenced commercial production.

Cash Flow

Operating activities: We used cash of $181,456 and $395,958 for the six month periods ended June 30, 2012 and 2011, respectively. The following is a breakdown of the cash and non-cash items used for operating activities, aside from the net income loss, respectively in each period: Impairment and depreciation of $481 and $2,604; Accretion of asset retirement obligation of $1,468 and $1,328; a non-cash gain in fair value of warrant liability of $0 and $3,000,648; changes in accounts receivable resulted in an decrease in cash of $9,858 and $12,270; changes in prepaid expenses resulted in a decrease in cash of $7,275 and $0; changes in accounts payable and accrued expenses (including related party) resulted in a decrease in cash of $24,797 and $9,906, respectively.

Investing Activities: During the six month period ended June 30, 2012 and 2011, there was $2,754 and $515,588 cash used in investing activities, respectively.

Financing Activities: We intend to finance our activities by raising capital through the equity markets. There were no financing activities during 2012 and 2011.

Dividends

We have neither declared nor paid any dividends on our common stock. We intend to retain our earnings to finance growth and expand our operations and do not anticipate paying any dividends on our common stock in the foreseeable future.

Fair Value of Financial Instruments and Risks

Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision. Changes in assumptions can significantly affect estimated fair value.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, accounts payable – related parties, and warrant liability approximate their fair value because of the short-term nature of these instruments.

Management is of the opinion that we are not exposed to significant interest or credit risks arising from these financial instruments.

We operate both inside and outside of the United States of America and are exposed to foreign currency risk due to the fluctuation between the Canadian dollar, in which our wholly owned subsidiary Fostung Resources operates in, and the U.S. dollar.

Share Capital

At August 15, 2012, we had:

Market Risk Disclosures

We have not entered into derivative contracts either to hedge existing risks or for speculative purposes during the year ended December 31, 2011, and the subsequent period to August 15, 2012.

Off-balance Sheet Arrangements and Contractual Obligations

We do not have any off-balance sheet arrangements or contractual obligations at December 31, 2011, and the subsequent period to August 15, 2012, that are likely to have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that have not been disclosed in our consolidated financial statements.

Effects of Inflation and Pricing

The crude oil and natural gas industry is cyclical and the demand for goods and services of crude oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for crude oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of crude oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of crude oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for crude oil and natural gas could result in increases in the costs of materials, services and personnel.

Environmental Compliance

Our current and future exploration and development activities, as well as our future mining and processing operations and oil and gas operations, are subject to various federal, state and local laws and regulations in the countries in which we conduct our activities. These laws and regulations govern the protection of the environment, prospecting, development, production, taxes, labor standards, occupational health, mine safety, toxic substances and other matters. We expect to be able to comply with those laws and do not believe that compliance will have a material adverse effect on our competitive position. We intend to obtain all licenses and permits required by all applicable regulatory agencies in connection with our mining operations and exploration activities. We intend to maintain standards of environmental compliance consistent with regulatory requirements.

We have an obligation to reclaim our properties after the surface has been disturbed by exploration methods at the site.

Critical Accounting Policies

Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Our accounting policies are described in “Note 2” to our December 31, 2011, consolidated financial statements. Significant areas requiring the use of management estimates include, the determination of impairment of mineral properties and oil and gas properties; useful lives for depreciation and amortization of property, plant and equipment; valuation allowances for future income tax assets and asset retirement obligations are critical accounting policies that are subject to estimates and assumptions regarding future activities are significant reporting areas impacted by management’s judgments and estimates. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

The more significant reporting areas impacted by management’s judgments and estimates are accruals related to oil and gas sales and expenses; estimates used in the impairment of oil and gas properties; and the estimated future timing and cost of asset retirement obligations. The carrying values of oil and gas properties are particularly susceptible to change in the near term. Changes in the future estimated oil and gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.

Mineral properties

We have concluded that mineral rights meet the definition of tangible assets. Accordingly, we account for our mineral properties on a cost basis whereby all direct costs, net of pre-production revenue, relative to the acquisition of the properties are capitalized. All sales and option proceeds received are first credited against the costs of the related property, with any excess credited to earnings. Once commercial production has commenced, the net costs of the applicable property will be charged to operations using the unit-of-production method based on estimated proven and probable recoverable reserves. The net costs related to abandoned properties are charged to operations.

Costs of exploring, carrying and retaining unproven properties are charged to operations as incurred until such time that proven reserves are discovered. From that time forward, we will capitalize all costs to the extent that future cash flow from mineral reserves equals or exceeds the costs deferred. The deferred costs will be amortized over the recoverable reserves when a property reaches commercial production. As at June 30, 2012 and December 31, 2011, we did not have proven reserves. Exploration activities conducted jointly with others are reflected at our proportionate interest in such activities.

Full Cost Method of Accounting for Oil and Gas Properties

We have elected to utilize the full cost method of accounting for its oil and gas activities. In accordance with the full cost method of accounting, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs and related asset retirement costs are capitalized.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves once proved reserves are determined to exist. We have not yet obtained reserve reports. Management is assessing production data to determine the feasibility of obtaining reserves studies. At June 30, 2012 and December 31, 2011, there were no capitalized costs subject to amortization.

Oil and gas properties without estimated proved reserves are not amortized until proved reserves associated with the properties can be determined or until impairment occurs.

Sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. We have not sold any oil and gas properties.

Full Cost Ceiling Test

At the end of each quarterly reporting period, the unamortized costs of oil and gas properties are subject to a “ceiling test” which basically limits capitalized costs to the sum of the estimated future net revenues from proved reserves, discounted at 10% per annum to present value, based on current economic and operating conditions, adjusted for related income tax effects.

Asset Retirement Obligation

We account for our future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement obligation is included in proven oil and gas properties in the balance sheets. Our asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method. Asset retirement obligations amounted to $56,784 and $55,316 at June 30, 2012 and December 31, 2011, respectively.

Oil and Gas Revenues

We recognize oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations, distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 45 days following the month of production. Therefore, we may make accruals for revenues and accounts receivable based on estimates of its share of production. Since the settlement process may take 30 to 60 days following the month of actual production, its financial results may include estimates of production and revenues for the related time period. We will record any differences between the actual amounts ultimately received and the original estimates in the period they become finalized.

Related Party Transactions

Our proposed business raises potential conflicts of interests between certain of our officers and directors and us. Certain of our directors are directors of other mineral resource companies and, to the extent that such other companies may participate in ventures in which we may participate, our directors may have a conflict of interest in negotiating and concluding terms regarding the extent of such participation. In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms. In appropriate cases, we will establish a special committee of independent directors to review a matter in which several directors, or management, may have a conflict. From time to time, several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, involvement in a greater number of programs and reduction of the financial exposure with respect to any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment.

In determining whether we will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the potential benefits to us, the degree of risk to which we may be exposed and our financial position at that time. Other than as indicated, we have no other procedures or mechanisms to deal with conflicts of interest. We are not aware of the existence of any conflict of interest as described herein.

Other than as disclosed below, during the six month period ended June 30, 2012 and the subsequent period to August 15, 2012, none of our current directors, officers or principal shareholders, nor any family member of the foregoing, nor, to the best of our information and belief, any of our former directors, senior officers or principal shareholders, nor any family member of such former directors, officers or principal shareholders, has or had any material interest, direct or indirect, in any transaction, or in any proposed transaction which has materially affected or will materially affect us.

For the six month periods ended June 30, 2012, fees of $7,500 (2011 - $9,000) and $16,689 (2011 - $18,000) were paid or are due to officers of the Company.

For the three and six month periods ended June 30, 2012, directors fees of $0 (2011 - $12,000 and $0 (2011 - $24,000) were paid to non-officer directors of the Company.

For the three and six month periods ended June 30, 2012, legal fees of $32,222 2011 – $18,375) and $44,966(2011 - $34,017) were paid or are due to Sierchio & Company, LLP, of which Mr. Sierchio, our Acting Interim President and Chief Executive and a director, is the managing partner. Included in accounts payable - related parties at June 30, 2012 is $27,383 (December 31, 2011 - $7,850) for legal fees.

These transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q for the three month period ended June 30, 2012, an evaluation was carried out under the supervision of and with the participation of our management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Exchange Act). Based on that evaluation the CEO and the CFO have concluded that as of the end of the period covered by this report, our disclosure controls and procedures are effective in ensuring that: (i) information required to be disclosed by us in reports that it files or submits to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms and (ii) material information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow for accurate and timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the period covered by this report, there were no changes to internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

None

Item 1A. Risk Factors

There are no material changes from the risk factors previously disclosed in Janus’ Form 10-K filed on March 29, 2012, with the SEC.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

None

Item 6. Exhibits

Exhibit Index

* Filed here herewith.

+ To be filed by amendment.

SIGNATURES

Pursuant to the requirements of Sections 13 or 15 (d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.