Edgar Filing: Janus Resources, Inc.

form10-q.htm

United States

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2011

£ 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)

Nevada		98-0170247
(State or other jurisdiction of incorporation)		(I.R.S. Employer Identification No.)

430 Park Avenue, Suite 702, New York, NY		10022
(Address of principal executive offices)		(Zip Code)

800-755-5815

(Registrant’s telephone number, including area code)

(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 T 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 o No o Not Applicable T

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.

Large accelerated filer	o		Accelerated filer	o
Non-accelerated filer	o		Smaller reporting company	T

Indicate by check mark whether the registrant is a shell company (as defined in 12b-2 of the Exchange Act)

Yes o No T

As of May 9, 2011, the registrant had 63,075,122 shares of its common stock, par value $0.00001 per share, issued and outstanding.

TABLE OF CONTENTS

JANUS RESOURCES, INC.

(Formerly Entheos Technologies, Inc.)

FORM 10-Q

For the Quarterly Period Ended March 31, 2011

PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements
	Balance Sheets as of March 31, 2011 (unaudited) and December 31, 2010	3
	Statements of Operations (unaudited)	4
	Statements of Cash Flows (unaudited)	5
	Notes to Financial Statements (unaudited)	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19

Item 4.	Controls and Procedures	19

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	20

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20

Item 3.	Defaults Upon Senior Securities	20

Item 4.	(Removed and Reserved)	20

Item 5.	Other Information	20

Item 6.	Exhibits	20

	Signatures	21

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

JANUS RESOURCES, INC.

(formerly Entheos Technologies, Inc.)

BALANCE SHEETS

	(Unaudited)
	March 31,			December 31,
	2011			2010

ASSETS
Current assets
Cash and cash equivalents	$	1,922,598		$	2,052,305
Accounts receivable		9,378			2,615
Total current assets		1,931,976			2,054,920

Oil and gas properties
Proven properties		432,089			432,089
Unproven properties		103,087			103,087
Accumulated depreciation, depletion, amortization and impairment		(509,886	)		(508,583	)
Oil and gas properties, net		25,290			26,593

Total assets	$	1,957,266		$	2,081,513

LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities
Accounts payable and accrued liabilities	$	23,617		$	9,404
Accounts payable - related parties		21,063			13,270
Warrant liability		5,242,205			5,248,041
Total current liabilities		5,286,885			5,270,715

Long-term liabilities
Asset retirement obligation		53,217			52,558
Total liabilities		5,340,102			5,323,273

STOCKHOLDERS' DEFICIT
Preferred stock: $0.0001 par value: Authorized: 10,000,000 shares
Issued and outstanding: nil		-			-
Common stock: $0.00001 par value: Authorized: 200,000,000 shares
Issued and outstanding: 63,075,122 shares (2010: 63,075,122)		631			631
Additional paid-in capital		5,462,236			5,462,236
Accumulated deficit		(8,845,703	)		(8,704,627	)

Total stockholders' deficit		(3,382,836	)		(3,241,760	)

Total liabilities and stockholders' deficit	$	1,957,266		$	2,081,513

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

Table of Contents

JANUS RESOURCES, INC.

(formerly Entheos Technologies, Inc.)

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2011			2010

Revenue
Oil and gas sales	$	7,633		$	11,735

Expenses
Lease operating expenses		5,171			6,697
General and administrative expenses		148,071			91,433
Impairment and depreciation		1,303			18,750
Total operating expenses		154,545			116,880

Operating Loss		(146,912	)		(105,145	)

Other income / (expense)
Change in fair value of warrant liability		5,836			(1,922,924	)

Net loss attributable to common stockholders	$	(141,076	)	$	(2,028,069	)


Net loss per common share - basic and diluted	$	(0.00	)	$	(0.03	)


Weighted average number of shares - basic and diluted		63,075,122			63,075,122

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

Table of Contents

JANUS RESOURCES, INC.

(formerly Entheos Technologies, Inc.)

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2011			2010

Cash flows from operating activities
Net loss	$	(141,076	)	$	(2,028,069	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Impairment and depreciation		1,303			18,750
Stock-based compensation		-			6,995
Accretion of asset retirement obligation		659			628
Change in fair value of warrant liability		(5,836	)		1,922,924
Changes in operating assets and liabilities:
Accounts receivable		(6,763	)		1,120
Accounts payable & accrued liabilities including related party payables		22,006			(106	)
Net cash flows from operating activities		(129,707	)		(77,758	)

Cash flows from investing activities
Acquisition of oil and gas properties		-			(7,118	)
Net cash flows from investing activities		-			(7,118	)

Decrease in cash and cash equivalents		(129,707	)		(84,876	)

Cash and cash equivalents, beginning of period		2,052,305			2,409,770
Cash and cash equivalents, end of period	$	1,922,598		$	2,324,894

Supplemental disclosure of cash flow information:
Interest paid in cash	$	-		$	-
Income tax paid in cash	$	-		$	-

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

Table of Contents

JANUS RESOURCES, INC.

(Formerly Entheos Technologies, Inc.)

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Janus Resources, Inc. (formerly Entheos Technologies, Inc.) (the “Company”, “we”, “us”, and “our”) is a small independent oil and gas production company with a focus on participation in producing oil and gas wells and the re-development/recompletion of oil and gas wells. The Company pursues oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise.

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.

Note 2. Basis of Presentation and Accounting Principles

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by generally accepted accounting principles (GAAP) in the United States (U.S.), and pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Therefore, this information should be read in conjunction with Janus Resources, Inc. financial statements and notes contained in its 2010 Annual Report on Form 10-K. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods reported. All such adjustments are, in the opinion of management, of a normal recurring nature. Operating results for the three-month period ended March 31, 2011, are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

Principles of Consolidation

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 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. 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.

Actual results could differ from the estimates as additional information becomes known. 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.

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.

Table of Contents

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 March 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. During the three month periods ended March 31, 2011 and 2010, there were no impairment charges.

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.

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

The Company accounts for its 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. 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. After their initial capitalization, the asset retirement obligation is allocated to operating expense using a systematic and rational method. Asset retirement obligations amounted to $53,217 and $52,558 at March 31, 2011 and December 31, 2010, respectively.

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. The Company is required to classify the fair value of the warrants issued as a liability, with subsequent changes in fair value to be recorded as income (loss) on change in fair value of warrant liability. The fair value of the warrants will continue to be classified as a liability until the warrants are exercised, expire or are amended in a way that would no longer require classification as a liability.

Oil and Gas Revenues

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 that may change in the near-term 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. The computation of diluted net income (loss) per common share is based on the weighted average number of shares used in the basic net income (loss) per share calculation plus the number of common shares that would be issued assuming the exercise of all potentially dilutive common shares outstanding using the treasury stock method for shares subject to stock options and warrants. See “Note 3. Earnings (Loss) Per Share” for further discussion.

Table of Contents

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 7. 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 the instruments. See Note 5 for further discussion on fair value of financial instruments.

Recent and Adopted Accounting Pronouncements

From time to time, new accounting guidance is issued by FASB that the Company adopts as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our financial statements upon adoption.

Note 3. Earnings (Loss) Per Share (EPS)

Dilutive common stock equivalents include 12,900,000 warrants for the three month period ended March 31, 2011 and 12,900,000 warrants and 150,000 stock options for the period ended March 31, 2010 which are not included in the computation of diluted earnings per share because to do so would be anti-dilutive. All share and per share information are adjusted retroactively to reflect stock splits and changes in par value, when applicable.

Following is the computation of basic and diluted net income (loss) per share for the periods ended March 31, 2011 and 2010:

	March 31,
	2011			2010

Numerator - net income (loss)	$	(141,076	)	$	(2,028,069	)

Denominator - weighted average number of common shares outstanding		63,075,122			63,075,122

Basic and diluted net income (loss) per common share	$	(0.00	)	$	(0.03	)

Note 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 March 31, 2011 and December 31, 2010 is as follows:

Table of Contents

	March 31,			December 31,
	2011			2010			Change ($)
Proven properties	$	432,089		$	432,089		$	-
Unproven properties		103,087			103,087			-
		535,176			535,176			-
Impairment and depletion, depreciation and amortization		(509,886	)		(508,583	)		(1,303	)
Oil and gas properties, net	$	25,290		$	26,593		$	(1,303	)

The Company depletes all capitalized costs of oil and gas properties on the unit-of-production method using proved reserves. 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 March 31, 2011 and December 31, 2010 there were no capitalized costs subject to depletion.

The costs of unproven properties as of March 31, 2011 and December 31, 2010 are associated with a development oil well which was completed in August 2009 and did not produce. Management has impaired the well to the extent of anticipated salvage value of the equipment. During January 2011, the operator of this well presented a two-phase drilling plan to the working interest owners that required a significant investment. Management determined to not participate in the plan due to the required capital investment and the risk of a dry well. According to the Joint Operating Agreement, the Company is subject to non-consent penalties that include a relinquishment of its interest in production from the well in favor of the participating working interest owners until the participating working interest owners have recovered 400% of the costs which would have been borne by the Company if it had elected to participate.

Depreciation, depletion, and amortization totaled by $1,303 and $18,570 for the three-months ended March 31, 2011 and 2010, respectively, and was determined using a systematic and rational method. Impairment for both three-months ended March 31, 2011 and 2010 was $nil as the Company believes that the carrying costs approximated fair market value. Amortization is not added to the cost of properties being amortized.

Asset Retirement Obligation

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

	March 31,		December 31,
	2011		2010
Asset retirement obligations, beginning of period	$	52,558	$	50,000
Accretion expense		659		2,558
Asset retirement obligations, end of period		53,217		52,558
Less: current portion		-		-
Long-term asset retirement obligations, end of period	$	53,217	$	52,558

Note 5. 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.

Table of Contents

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

Warrant Liability. Warrant liability derivatives are valued at each quarter-end using the Black-Scholes option pricing model and are affected by changes in inputs to that model including the Company’s stock price, expected stock price volatility, the contractual term, and the risk-free interest rate. These unobservable inputs reflect the Company’s own assumptions that market participants would use in pricing the liability. Given the unobservable nature of the inputs, the measurement of fair value is deemed to use Level 3 inputs. The changes in value are recognized as other income (expense) in the statements of operations. A reconciliation of the beginning and ending balances and changes in the warrant liability are included in Note 6.

The following table presents the Company’s financial liabilities, which were accounted for at fair value on a recurring basis as of March 31, 2011, by level within the fair value hierarchy.

	March 31, 2011
	Level 1		Level 2		Level 3		Total
LIABILITIES
Warrant liability	$	-	$	-	$	5,242,205	$	5,242,205

The following table presents the Company’s financial liabilities, which were accounted for at fair value on a recurring basis as of December 31, 2010, by level within the fair value hierarchy:

	December 31, 2010
	Level 1		Level 2		Level 3		Total
LIABILITIES
Warrant liability	$	-	$	-	$	5,248,041	$	5,248,041

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.

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. See Note 4 for a summary of changes in the Company’s asset retirement obligation.

The following table presents the Company’s assets and liabilities, which were accounted for at fair value on a non-recurring basis as of March 31, 2011, by level within the fair value hierarchy.

Table of Contents

	March 31, 2011
	Level 1		Level 2		Level 3		Total
ASSETS
Oil and gas properties, net	$	-	$	-	$	25,290	$	25,290

LIABILITIES
Asset retirement obligation	$	-	$	-	$	53,217	$	53,217

The following table presents the Company’s assets and liabilities, which were accounted for at fair value on a non-recurring basis as of December 31, 2010, by level within the fair value hierarchy.

	December 31, 2010
	Level 1		Level 2		Level 3		Total
ASSETS
Oil and gas properties, net	$	-	$	-	$	26,593	$	26,593

LIABILITIES
Asset retirement obligation	$	-	$	-	$	52,558	$	52,558

Note 6. Stockholders’ Equity

As of March 31, 2011, the Company had outstanding 6,450,000 Series A warrants and 6,450,000 Series B warrants each allowing the holder to purchase one share of the Company’s common stock at a purchase price of $0.60 and $0.75 per share, respectively. The warrants currently have an expiration date of December 31, 2011.

The warrant terms include a “Dilutive Issuance” clause that could result in a settlement amount that does not equal the difference between the fair value of a fixed number of the Company’s common stock and a fixed exercise price. Accordingly, the warrants are not considered indexed to the Company’s stock and, therefore, are accounted for as a derivative pursuant to ASC 815-40 Contracts in an Entity’s Own Equity. As of March 31, 2011, the Company has not sold any shares of common stock or common stock equivalents that would result in an adjustment to the exercise price or number of shares of common stock underlying the warrants outstanding thereby triggering the Dilutive Issuance feature.

At March 31, 2011, the Company valued the warrant liability using a Black-Scholes model (Level 3 inputs) containing the following assumptions:

	Series A Warrants			Series B Warrants
Warrants outstanding and exercisable at March 31, 2011		6,450,000			6,450,000
Exercise price	$	0.60		$	0.75
Black-Scholes option pricing model assumptions:
Risk-free interest rate		0.235	%		0.235	%
Expected term (in years)		0.75			0.75
Expected volatility		123.49	%		123.49	%
Dividend per share	$	0		$	0
Expiration date	December 31, 2011			December 31, 2011

The following table is a roll forward of the fair value of the warrant liability related to the common stock warrants using the Black-Scholes assumptions as of March 31, 2011 (Level 3 inputs):

	Series A Warrants		Series B Warrants			Total
Balance as of December 31, 2010	$	2,744,200	$	2,503,841		$	5,248,041
Change in fair value		58,652		(64,488	)		(5,836	)
Ending balance, March 31, 2011	$	2,802,852	$	2,439,353		$	5,242,205

As a result of adjusting the warrant liability to fair value, we recorded a non-cash loss of $58,652 and a non-cash gain of $64,488 relating to the Series A and Series B Warrants, respectively, for the three month period ended March 31, 2011.

Table of Contents

Note 7. Related Party Transactions

Executive Management

On August 27, 2010, Mr. Derek Cooper resigned from the positions of President, Chief Executive Officer, Chief Financial Officer and Director of the Company. The Company incurred $nil and $7,500 in fees paid to Mr. Cooper for the three month periods March 31, 2011 and 2010, respectively.

Immediately upon Mr. Cooper’s resignation, the Company appointed Mr. Antonino Cacace to the Board of Directors and the positions of President, Chief Executive Officer and Chief Financial Officer. The Company has agreed to pay Mr. Cacace a monthly management fee of $3,000 for his services. For the three month periods ended March 31, 2011 and 2010, the Company incurred $9,000 and $nil, respectively, in management fees paid to Mr. Cacace.

Director Fees

On August 26, 2010, the Company appointed Messrs. David Jenkins and Joseph Sierchio to the Board of Directors. The Company has agreed to pay Messrs. Jenkins and Sierchio a monthly fee of $2,000 each for their services. For the three month periods ended March 31, 2011 and 2010, the Company has incurred $12,000 and $nil in management fees paid to Messrs. Jenkins and Sierchio.

Legal Fees

Legal fees expensed for the three month periods ended March 31, 2011 and 2010, totaled $15,642 and $9,030, respectively, were paid or are due to Mr. Sierchio.

Table of Contents

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

Forward-Looking Statements

Except for the historical information presented in this document, the matters discussed in this Form 10-Q for the three-months ended March 31, 2011, and specifically in the items entitled "Management’s Discussion and Analysis of Financial Condition and Results of Operations," or otherwise incorporated by reference into this document, contain "forward-looking statements" (as such term is defined in the Private Securities Litigation Reform Act of 1995). These statements are identified by the use of forward-looking terminology such as "believes," "plans," "intend," "scheduled," "potential," "continue," "estimates," "hopes," "goal," "objective," expects," "may," "will," "should," or "anticipates" or the negative thereof or other variations thereon or comparable terminology, or by discussions of strategy that involve risks and uncertainties.

The safe harbor provisions of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, apply to forward-looking statements made by the Company. The reader is cautioned that no statements contained in this Form 10-Q should be construed as a guarantee or assurance of future performance or results. These forward-looking statements involve risks and uncertainties, including those identified within this Form 10-Q. The actual results that the Company achieves may differ materially from any forward-looking statements due to such risks and uncertainties. These forward-looking statements are based on current expectations, and the Company assumes no obligation to update this information. Readers are urged to carefully review and consider the various disclosures made by the Company in this Form 10-Q and in the Company's other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect the Company's business.

Overview

Incorporated under the laws of the State of Nevada, we have an authorized capital of 200,000,000 shares of $0.00001 par value common stock, of which 63,075,122 shares are outstanding and 10,000,000 shares of $0.0001 par value preferred stock, of which none are outstanding.

Our principal executive offices are located at 430 Park Avenue, Suite 702, New York, NY, 10022. Our telephone number is 800-755-5815.

Description of Business

We are a small independent energy company engaged in the acquisition and development of crude oil and natural gas interests in the United States. We pursue oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise. We currently have interests in producing properties in La Salle County, Fayette County, Lee County and Frio County, Texas.

The leases for these properties are maintained and operated by our partners Leexus Oil LLC and Bayshore Exploration LLC; 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 the Company 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.

Management Changes

On August 26, 2010, Messrs. Jeet Sidhu and Christian Hudson resigned as members of the Board of Directors. In order to fill the vacancies created by their resignations, we appointed Messrs. David Jenkins and Joseph Sierchio to the Board of Directors. We have agreed to pay Messrs. Jenkins and Sierchio a monthly fee of $2,000 each for their services.

On August 27, 2010, Mr. Derek Cooper resigned from the positions of President, Chief Executive Officer, Chief Financial Officer and Director of the Company. Immediately upon Mr. Cooper’s resignation, we appointed Mr. Antonino Cacace, to the Board of Directors and to the positions of President, Chief Executive Officer and Chief Financial Officer. We have agreed to pay Mr. Cacace a monthly management fee of $3,000 for his services.

The resignation of each Messrs. Cooper, Hudson and Sidhu was not the result of a disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

Oil and Gas Properties

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

Table of Contents

								Month
	Acquisition	Interest						Production
	Date	Working			Net Revenue			Started		Acreage		Formation
Proven Properties:
Cooke #6	9/1/2008		21.75	%		16.3125	%	Dec-07			40	Escondido
Onnie Ray #1	9/12/2008		20.00	%		15.00	%	Oct-08			80	Austin Chalk
Stahl #1	9/12/2008		20.00	%		15.00	%	Oct-08			20	Austin Chalk
Pearce #1	10/31/2008		20.00	%		15.00	%	Dec-08			360	Austin Chalk
Unproven Properties:
Haile #1	9/12/2008		20.00	%		15.00	%		-		100	Austin Chalk

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 March 31, 2011 and December 31, 2010 are summarized as follows:

	March 31,			December 31,
	2011			2010			Change ($)
Proven properties	$	432,089		$	432,089		$	-
Unproven properties		103,087			103,087			-
		535,176			535,176			-
Impairment and depletion, depreciation and amortization		(509,886	)		(508,583	)		(1,303	)
Oil and gas properties, net	$	25,290		$	26,593		$	(1,303	)

Depreciation, depletion, and amortization totaled $1,303 and $18,570 for the three-months ended March 31, 2011 and 2010, respectively, and was determined using a systematic and rational method. Impairment for the three-months ended March 31, 2011 and 2010 was $nil as the Company believes that the carrying costs approximated fair market value.

The unproven property is a well completed in August 2009 which did not produce. Management has impaired the well to the extent of the anticipated salvage value of the equipment. During January 2011, the operator of this well presented a two-phase drilling plan to the working interest owners that required a significant investment. Management determined to not participate in the plan due to the required capital investment and the risk of a dry well. According to the Joint Operating Agreement the Company is subject to non-consent penalties that include a relinquishment of its interest in production from the well in favor of the participating working interest owners until the participating working interest owners have recovered 400% of the costs which would have been borne by the Company if it had elected to participate.

Critical Accounting Policies

Full Cost Method of Accounting for Oil and Gas Properties

Table of Contents

Full Cost Ceiling Test

Asset Retirement Obligation

Warrant Liability Derivative

Oil and Gas Revenues

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.

Recent and Adopted Accounting Pronouncements

The Company reviews new accounting standards as issued. Although some of these accounting standards issued or effective after the end of our previous fiscal year may be applicable to us, the Company expects that none of the new standards will have a significant impact on our financial statements.

Variables and Trends

We have very limited history with respect to our acquisition and development of oil and gas properties. In the event we are able to obtain the necessary financing to move forward with our growth plans, we expect our expenses to increase significantly as we grow our business. Accordingly, the comparison of the financial data for the periods presented may not be a meaningful indicator of our future performance and must be considered in light of these circumstances.

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.

Table of Contents

“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. The Company has 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.

Table of Contents

Results of Operations

The following table sets forth certain unaudited operating information with respect to the Company's oil and gas operations for the periods indicated:


	Three Months Ended March 31,
	2011			2010			change			% change
Production:
Oil (Bbls)		66.1			124.0			(57.9	)		(47	%)
Gas (Mcf)		241.7			337.4			(95.7	)		(28	%)
Total production (BOE)		106.4			180.2			(73.8	)		(41	%)
Average daily production (BOE)		1.2			2.0			(0.8	)		(40	%)
% oil of production		62	%		69	%		(7	%)		(10	%)

Average sales price:
Oil (per Bbl)	$	84.25		$	72.09		$	12.16			17	%
Gas (per Mcf)	$	8.55		$	8.29		$	0.26			3	%
Total production (per BOE)	$	71.76		$	65.13		$	6.63			10	%

Oil and gas revenues:
Oil revenue	$	5,567		$	8,936		$	(3,369	)		(38	%)
Gas revenue	$	2,066		$	2,799		$	(733	)		(26	%)
Total	$	7,633		$	11,735		$	(4,102	)		(35	%)
Lease operating expenses	$	5,171		$	6,697		$	(1,526	)		(23	%)

Additional per BOE data:
Sales price	$	71.76		$	65.13		$	6.63			10	%
Lease operating expenses	$	48.62		$	37.17		$	11.45			31	%
Operating Margin per BOE	$	23.14		$	27.96		$	(4.82	)		(17	%)

Impairment and DDA	$	1,303		$	18,750		$	(17,447	)		(93	%)

General and administrative:
Management fees	$	21,000		$	14,495		$	6,505			45	%
Accounting & legal	$	73,047		$	58,051		$	14,996			26	%
Consulting, travel, and investor relations	$	54,024		$	18,887		$	35,137			186	%
Total	$	148,071		$	91,433		$	56,638			62	%

Change in fair value of warrant liability	$	5,836		$	(1,922,924	)	$	1,928,760			(100	%)

Total Revenue

Total oil and gas revenues decreased 35% to $7,633 from $11,735 comparatively for the three-month periods ended March 31, 2011 to 2010 due to a decrease in production from the natural decline in the reservoirs. Average daily production on an equivalent basis for the three-month period ended March 31, 2011 was 1.2 BOE compared to 2.0 BOE for the same period in 2010 which represents a decrease of 40%. Oil comprised 62% of our production volume for the three month period ended March 31, 2011 compared to 69% for the same period in 2010.

Oil Revenue

Oil production for the three-months ended March 31, 2011 and 2010 was 66.1 barrels and 124.0 barrels, respectively and generated revenue of $5,567 and $8,936, respectively, for an average price per barrel of $84.25 and $72.09, respectively. The 47% decrease in production was offset by the 17% increase in price per barrel.

Gas Revenue

Gas production for the three-months ended March 31, 2011 and 2010 was 241.7 and 337.4 Mcf, respectively, and generated revenue of $2,066 and $2,799, respectively, for an average price per Mcf of $8.55 and $8.29, respectively. The 28% decrease in production was offset by a 3% increase in price per Mcf. We continue to receiving premium pricing on gas production due to high quality, or high Btu, gas.

Table of Contents

Lease Operating Expenses

Lease operating expenses for the three-months ended March 31, 2011 and 2010 were $5,171 and $6,697, respectively. The 23% decrease is attributable to reduced maintenance costs and increased operator efficiency. On an equivalent production basis this represents a decrease of 17% to $23.14 per BOE from $27.96 per BOE.

Impairment and DDA

Management Fees

Management fees for the three-months ended March 31, 2011 were $21,000 and $14,495, respectively. The $6,505 increase is due to a change in compensation structure upon the change in the management team in August 2010. The changes in the compensation structure include monthly compensation for services provided as executives and board members but do not include stock option based compensation.

Accounting and Legal Fees

Accounting and legal expenses for the three-months ended March 31, 2011 and 2010 were $73,047 and $58,051, respectively. The $14,996 increase is comprised of an $8,384 increase in accounting fees due to the change in management in August 2010, and an increase of $6,612 in legal expenses.

Consulting, Travel and Investor Relations

Consulting, travel and investor relations expenses for the three month periods ended March 31, 2011 and 2010 were $54,024 and $18,887, respectively. The $35,137 increase is due to an increase in consulting fees of $20,263 and an increase in travel expense of $20,845 as the Company explores investment opportunities; and a decrease of $5,479 in office, facilities fees and investor relations.

Change in Fair Value of Warrant Liability

We measure the fair value of the warrant liability in accordance with ASC 820 Fair Value Measurement and Disclosure which emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, ASC 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within Levels 1 and 2 of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within Level 3 of the hierarchy). At the end of each reporting period, we revalue the warrant liability using a Black-Scholes model (Level 3 inputs). As a result of adjusting the warrant liability to fair value, we recorded a non-cash gain of $58,652 and a non-cash loss of $64,488 (net gain of $5,836) relating to the Series A and Series B Warrants, respectively, for the three-months ended March 31, 2011.

Liquidity and Capital Resources

We had cash and cash equivalents of $1,922,598 and $2,052,305 as of March 31, 2011 and December 31, 2010, respectively. We have financed our operations from cash on hand for the three-months ended March 31, 2011.

Net cash flows used in operating activities was ($129,707) for the three-months ended March 31, 2011 compared to net cash used in operating activities of ($77,758) for the three-month ended March 31, 2010. Cash used for operating activities increased primarily due to increased general and administrative expenses.

Cash used in investing activities was $nil for the three-months ended March 31, 2011, compared to cash used in investing activities of $7,118 for the three-months ended March 31, 2010. The cash used represents additions to capitalized costs of oil and gas properties.

We had no cash used or generated in financing activities for the three month periods ended March 31, 2011 and 2010.

Table of Contents

Recently Issued Accounting Pronouncements

See Note 2 in the Notes to the Financial Statements in this Report.

Related Party Transactions

See Note 7 in the Notes to the Financial Statements in this Report.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company’s principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) were effective as of March 31, 2011.

There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceeding

None

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

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Removed and Reserved

Item 5. Other Information

None

Item 6. Exhibits

Exhibit Index

Exhibit No.		Description of Exhibit

3.1		Articles of incorporation (exhibit 3.1). S-8 filing dated October 3, 2003.

3.2		Bylaws (exhibit 3.2). S-8 filing dated October 3, 2003.

10.1		Subscription Agreement (exhibit 10.1), Series A Warrant Agreement (exhibit 10.2), Series B Warrant Agreement (exhibit 10.2), Registration Rights Agreement (exhibit 10.4) for 6,450,000 unit private placement on July 28, 2008. 8-K filing dated August 1, 2008.

10.2		Participation Agreement dated September 9, 2008 with respect to the Stahl #1 Well located Fayette County, Texas. 8-K filing dated October 24, 2008.

10.3		Participation Agreement dated September 9, 2008 with respect to the Onnie Ray #1 Well located Lee County, Texas. 8-K filing dated October 24, 2008.

10.4		Participation Agreement dated September 9, 2008 with respect to the Haile #1 Well located Frio County, Texas. 8-K filing dated October 24, 2008.

10.5		2001 Incentive Stock Option Plan (exhibit 99.1). S-8 filing dated October 3, 2003.

14.1		Code of Ethics. 10-K filing dated April 14, 2009.

31.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a).*

32.1*		Certification by the Chief Executive Officer pursuant to 18 U.S.C. 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

*Filed here within.

Table of Contents

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 on this 16th day of May, 2011.

		Janus Resources, Inc.
		(Registrant)


Date	Signature	Title
May 16, 2011	/s/ Antonino Cacace	President, Chief Executive Officer,
	Antonino Cacace	Chief Financial Officer and Director