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, 2010

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

For the transition period from _____ to _____

ENTHEOS TECHNOLOGIES, INC.

 (Exact name of registrant as specified in its charter)

403-444-6418

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.         

YesT         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.

PART I   — FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

ENTHEOS TECHNOLOGIES, INC.

NOTES TO FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2010

(Unaudited)

Note 1. Organization and Nature of Operations

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. We pursue oil and gas prospects in partnership with oil and gas companies with exploration, development and production expertise.  Currently, our interests consist of non-operating, minority working interests. The Company’s prospect areas consist of land in La Salle County, Lee County, Fayette County and Frio County, Texas. Currently four of the five wells in which the Company has minority working interests are producing. The Company does not operate any of the wells in which it has an interest.

Incorporated under the laws of the State of Nevada, the Company has 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.

The Company has recently incurred net operating losses and operating cash flow deficits. 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 2011 if not further.  The future of the Company after December 2011 will depend in large part on its ability to successfully generate cash flows from operations and raise capital from external sources to fund operations.

Note 2. Significant Accounting Policies

The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, all adjustments (which are of a normal recurring nature) considered necessary for a fair presentation of the financial statements have been included. Operating results for the quarter ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010 or any other interim period. For further information, refer to the financial statements and notes thereto included in our 2009 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission.

References to Authoritative Accounting Literature

In June 2009, the Financial Accounting Standards Board ("FASB") issued the Accounting Standards Codification ("ASC") as the single source of authoritative accounting principles generally accepted in the United States of America (“U.S. GAAP”) recognized by the FASB to be applied by non-governmental entities in preparation of financial statements in conformity with U.S. GAAP, except for additional authoritative rules and interpretative releases issued by the SEC.  While the adoption of the ASC changes how we reference accounting standards, the adoption did not have an impact on our financial statements.

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.

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 warrant derivative liabilities; 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.

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, 2010, 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. The cost of these properties is assessed quarterly, on a property-by-property basis, to determine whether the properties 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.

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.

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.

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. The asset retirement obligation is allocated to operating expense using a systematic and rational method considering the estimated remaining life of the well.

Fair Value

We measure fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the reporting date. We utilize a three-tier hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access.  We have no assets or liabilities valued with Level 1 inputs.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities.      We have no assets or liabilities valued with Level 2 inputs. 

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Liabilities valued with Level 3 inputs are described in “Note 5. Stockholders’ Equity” and “Note 4. Oil and Gas Properties.”

Warrant Derivative Liability

We evaluate financial instruments for freestanding or embedded derivatives.  The warrant derivative liability is recorded at fair value with changes in value recognized as other income (expense) in the statements of operations in the period of change.

Stock-Based Compensation

We measure all stock-based compensation awards at fair value on the date of grant and recognize such expense in our financial statements over the requisite service period for awards expected to vest.  The Company uses the Black-Scholes pricing model to determine the fair value of stock-based compensation awards on the date of grant.  The Black-Scholes pricing model requires management to make assumptions regarding the option lives, expected volatility, and risk free interest rates. See “Note 6. Stock Options” for additional information on the Company’s stock-based compensation plans.

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 period. 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.

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”).

Recent and Adopted Accounting Pronouncements

We review 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, we expect that none of the new standards will have a significant impact on our financial statements.

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

Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted EPS is computed by dividing net income attributable to common stockholders by the weighted average number of common and potential common shares outstanding during the period, which includes the additional dilution related to conversion of stock options and common stock purchase warrants as computed under the treasury stock method.

For the three and six month periods ended June 30, 2010 and 2009, potential gross common shares (arising from stock options and common stock purchase warrants) of 13.1 million were anti-dilutive and not included in computing diluted EPS.

 Note 4. Oil and Gas Properties

As of June 30, 2010, the Company owned non-operating, working interests in five wells in one geographic area as follows:

Costs incurred for oil and gas property properties are summarized as follows as of June 30, 2010:

The Company amortizes 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 for the six month periods ended June 30, 2010 and 2009, there were no capitalized costs subject to amortization.

Unproven properties costs as of June 30, 2010 are associated with a development oil well which was completed in August 2009 and did not produce. Management has considered the well impaired to the extent of anticipated salvage value of the equipment. 

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 proved reserves, the Company recorded an impairment loss of $12,758 (2009: $198,581) and $12,758 (2009: $245,421) for the three and six month periods ended June 30, 2010, respectively.  The impairment is similar to amortization and therefore is not added to the cost of properties being amortized.  Depreciation amounted to $9,374 and $nil for the three month periods ended June 30, 2010 and 2009, respectively.  Depreciation amounted to $28,125 and $nil for the six month periods ended June 30, 2010 and 2009, respectively.

Asset Retirement Obligation

The following table summarizes the activity for the Company’s asset retirement obligations for the six month periods ended June 30, 2010 and 2009:

The carrying value of asset retirement obligations were measured using Level 3 inputs, as defined in the fair value hierarchy.

Note 5. Stockholders’ Equity

On July 28, 2008, the Company completed a self-directed private placement of 6,450,000 units at a price of $0.50 per unit or $3,225,000 in the aggregate. Each unit consists of one share of the Company’s common stock, one Series A stock purchase warrant (“Series A warrant”) to purchase one share of common stock at $0.60 per share for a period of 18 months from the date of issuance and one Series B stock purchase warrant (“Series B warrant”) to purchase one share of common stock at $0.75 per share for a period of 24 months from the date of issuance (refer to the “Warrants” section below for a discussion of the extension of the expiration date of the warrants).

In connection with the private placement, the Company issued an aggregate of 50,000 units in payment of legal fees in the amount of $25,000. These units were otherwise issued on the same terms and conditions as the units sold in the private placement.

Pursuant to the Subscription Agreement and the Registration Rights Agreement relating to the private placement, the Company and the investor parties made other covenants and representations and warranties regarding matters that are customarily included in financings of this nature. In the event that during the period when the warrants are outstanding, if the Company issues common stock or common stock equivalents at a price per share which is less than the warrant exercise price, $0.60 per share for Series A warrants and $0.75 per share for Series B warrants, then the exercise price for the warrants shall be reduced to equal the share price of the new issuance and the number of warrant shares issuable shall be increased such that the aggregate exercise price payable shall be equal to the aggregate exercise price prior to such adjustment according to the Securities Purchase Agreement (the “Dilutive Issuance”).

Warrants

Each of the Company’s warrants outstanding entitles the holder to purchase one share of the Company’s common stock for each warrant share held. No warrants were exercised during the six month periods ended June 30, 2010 and 2009. 

On December 14, 2009, the Company extended the expiration date of the 6,450,000 Series A warrants from January 28, 2010 to July 28, 2010 and extended the expiration date of the 6,450,000 Series B warrants from July 28, 2010 to January 28, 2011.  The exercise price of the warrants remains unchanged at $0.60 and $0.75 for the Series A and Series B warrants, respectively.

On January 27, 2010, the Company extended the expiration date of 6,450,000 Series A warrants again from July 28, 2010 to January 28, 2011 and extended the expiration date of the 6,450,000 Series B warrants again from January 28, 2011 to July 28, 2011. The exercise price of the warrants remains unchanged at $0.60 per share and $0.75 per share for the Series A and Series B warrants, respectively.

The potential of a Dilutive Issuance to the warrants’ exercise price and number of underlying shares of common stock may 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 own stock and, therefore, are accounted for as a derivative pursuant to ASC 815-40   Contracts in an Entity’s Own Equity   which became effective January 1, 2009 .   Upon the adoption of this guidance, the Company recognized a one-time decrease to opening accumulated deficit of $1,624,513.

As of June 30, 2010, 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.  Additionally, the Company does not intend to sell any shares of common stock or common stock equivalents at a price that is below the exercise price of the warrants, prior to their expiration dates, which would result in an adjustment to the exercise price or number of shares of common stock underlying the warrants.  Since the Company determined that the future probability of a Dilutive Issuance is deemed unlikely, it did not have a material impact on the fair value estimate of the warrant liability at June 30, 2010 as it relates to the Series A or Series B Warrants.

At June 30, 2010, the Company valued the warrant liability using a Black-Scholes model (Level 3 inputs) containing the following assumptions:

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 June 30, 2010 (Level 3 inputs):

As a result of adjusting the warrant liability to fair value, we recorded a non-cash loss of $444,507 and a non-cash gain of $460,107 relating to the Series A and Series B Warrants, respectively, for the six month period ended June 30, 2010.

A total of 12,900,000 shares of the Company’s common stock have been reserved for issuance upon exercise of Series A and Series B warrants outstanding as of June 30, 2010.

Note 6. Stock Options

The Company has an active stock option plan that provides shares available for option grants to employees, directors and others. A total of 120,000,000 shares of the Company’s common stock have been reserved for award under the stock option plan, of which 119,850,000 were available for future issuance as of June 30, 2010.  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 periods ended June 30, 2010 and 2009, the Company did not grant any stock options awards. 

During the three and six month periods ended June 30, 2010, stock-based compensation expense of $6,995 (2009: $12,445) and $13,991 (2009: $25,582) was recognized as general and administrative expenses. As of June 30, 2010, the Company had $37,078 of total unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted average period of approximately 3.21 years.

The Company does not repurchase shares to fulfill the requirements of options that are exercised. Further, the Company issues new shares when options are exercised.

Note 7. Related Party Transactions

Executive Management: For the three and six month periods ended June 30, 2010, the Company incurred $7,500 (2009: $7,500) and $15,000 (2009: $15,000) in fees paid to Derek Cooper the President, Chief Executive Officer and Chief Financial Officer of the Company. In addition, the Company recorded $2,332 (2009: $4,148) and $4,664 (2009: $8,297) as stock compensation expense related to options granted to Derek Cooper (refer to “Note 6. Stock Options”) for the three and six month periods ended June 30, 2010, respectively.

Director Fees: For the three and six month periods ended June 30, 2010, the Company incurred nil (2009: $6,000) and nil (2009: $12,435), respectively, in board fees for non-employee directors of the Company. In addition, the Company recorded $4,663 (2009: $8,297) and $8,989 (2009: $17,285) as stock compensation expense related to options granted to non-employee directors (refer to “Note 6. Stock Options”) for the three and six months ended June 30, 2010, respectively. 

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 six months ended June 30, 2010, 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, the Company has 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 888 3^rd Street SW, Suite 1000, Calgary Alberta, Canada T2P 5C5.  Our telephone number is (403) 444-6418. 

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.

Oil and Gas Properties

The following table sets forth a summary of our current 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, 2010 and December 31, 2009 are summarized as follows:

Capital expenditures totaled $8,119 for the six month period ended June 30, 2010 in order to correct a tubing puncture in the Onnie Ray #1 well and to pay a lease royalty.  An authorization for expenditure totaling $7,500, was submitted to us by the well operator in January 2010 and the workover was completed in March 2010.  Immediately upon completion of the workover production increased; however the increased production has not been sustained over the quarter ended June 30, 2010.  Depreciation, depletion, amortization and impairment totaled by $9,374 and $28,125 for the three and six month periods ended June 30, 2010, respectively, and was determined using a systematic and rational method.

The Company recorded an impairment loss of $12,758 for the three and six month periods ended June 30, 2010. 

At the time of acquisition, the unproven property, 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. 

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. 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 warrant derivative liabilities; 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.

References to Authoritative Accounting Literature

In June 2009, the Financial Accounting Standards Board ("FASB") issued the Accounting Standards Codification ("ASC") as the single source of authoritative accounting principles generally accepted in the United States of America ("U.S. GAAP") recognized by the FASB to be applied by non-governmental entities in preparation of financial statements in conformity with U.S. GAAP, except for additional authoritative rules and interpretative releases issued by the SEC.  While the adoption of the ASC changes how we reference accounting standards, the adoption did not have an impact on our financial statements.

Full Cost Method of Accounting for Oil and Gas Properties

We have elected to 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.

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 because of our recent acquisition of our oil and gas properties and because these properties recently began producing. Management is assessing geographic and production data to determine the need for reserves studies. At June 30, 2010, 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. The cost of these properties is assessed quarterly, on a property-by-property basis, to determine whether the properties are recorded at the lower of cost or fair market value. In determining whether such costs should be impaired, we evaluate 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. As a result of this analysis and lack of proved reserves, we recorded an impairment loss of $12,758 and $245,421 for the six month periods ended June 30, 2010 and 2009, respectively. The impairment is similar to amortization and therefore is not added to the costs of properties being amortized.

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 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.

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 our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our 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.

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 cost is included in proved 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 our oil and gas properties and gathering assets. The asset retirement obligation is allocated to operating expense using a systematic and rational method considering the estimated remaining life of the well.

Fair Value

We measure fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the reporting date. We utilize a three-tier hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:

Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access.  We have no assets or liabilities valued with Level 1 inputs.

Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities.      We have no assets or liabilities valued with Level 2 inputs. 

Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Liabilities valued with Level 3 inputs are described in “Note 5. Stockholders’ Equity” and “Note 4.  Oil and Gas Properties” in the Notes to Financial Statements.

Recent and Adopted Accounting Pronouncements

We review 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, we expect 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.

“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.

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:

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

Total Revenue

Total oil and gas revenues decreased 11% from $13,842 to $12,353 comparatively for the three month periods ended June 30, 2009 to 2010 due to a decline in production from the natural decline in the reservoirs.  Average daily production on an equivalent basis for the three month period ended June 30, 2010 was 2.1 BOE compared to 3.5 BOE for the same period in 2009 which represents a decrease of 41%.  Oil remains the majority of our revenue mix at 70% and 75% for the three-month periods ended June 30, 2010 and 2009, respectively.

Oil Revenue

Oil production for the three month periods ended June 30, 2010 and 2009 was 130.0 and 238.0 barrels, respectively, and generated revenue of $9,904 and $11,500, respectively, for an average price per barrel of $76.19 and $48.32.  The 45% decrease in production was offset by the 58% increase in price per barrel.

Oil production for the six month periods ended June 30, 2010 and 2009 was 256.4 and 540.7 barrels, respectively, and generated revenue of $18,840 and $22,579, respectively, for an average price per barrel of $73.49 and $41.76, respectively.  The 53% decrease in production was offset by the 76% increase in price per barrel.

Gas Revenue

Gas production for the three month period ended June 30, 2010 and 2009 was 336.8 and 464.7 Mcfs, respectively, and generated revenue of $2,449 and $2,342, respectively, for an average price per Mcf of $7.27 and $5.04, respectively.  The 28% decrease in production was offset by a 44% increase in price per Mcf.

Gas production for the six month period ended June 30, 2010 and 2009 was 674.1 and 1,244.9 Mcf, respectively, and generated revenue of $5,247 and $6,047, respectively, for an average price per of $7.78 and $4.86 per Mcf, respectively.  The decrease in production is due to the natural decline in reservoirs.  The 46% decrease in production was offset by the 60% increase in price per Mcf.  In addition to optimizing the current well production rates management is actively looking to add to our production base.

Lease Operating Expenses

Lease operating expenses for the three month period ended June 30, 2010 decreased 52% or $5,433 to $4,942 from $10,375 for the same period in 2009.  This decrease is attributable to increased operator efficiency; reduced maintenance costs primarily from Haile which had not been determined to be dry as of August 2009, and due to a lump sum reimbursement of production taxes from the Texas Severance Tax Incentive.  Lease operating expenses on an equivalent production basis decreased 6.34 per BOE to 26.55 from 32.89 or 19% due to lower operating expenses. 

Lease operating expenses for the six month period ended June 30, 2010 decreased 54% to $11,639 from $25,078 for the same period in 2009.  This decrease is attributable to increased operator efficiency as well as reduced maintenance costs as several of the wells had recently begun producing in the first quarter of 2009.  Lease operating expenses on an equivalent production basis decreased 1.95 per BOE to 31.57 from 33.52 or 6% due to operator efficiency as well as reduced maintenance costs. 

Impairment and DDA

The impairment of oil and gas properties decreased to $12,758 from $198,581 comparatively for the three month periods ended June 30, 2010 and 2009, respectively.  We believe that our net book value approximates fair market value. Depreciation amounted to $9,374 for the three months ended June 30, 2010.

The impairment of oil and gas properties decreased to $12,758 from $245,421 comparatively for the six month periods ended June 30, 2010 and 2009, respectively.  We believe that our net book value approximates fair market value. Depreciation amounted to $28,125 for the six months ended June 30, 2010.

Management Fees

Management fees decreased to $14,496 from $25,945 comparatively for the three month periods ended June 30, 2010 and 2009. The $11,449 decrease is comprised of a $6,000 decrease in director’s fees and a $5,449 decrease in stock-based compensation expense.

Management fees decreased to $28,992 from $53,018 comparatively for the six month periods ended June 30, 2010 and 2009. The $24,026 decrease is comprised of a $12,435 decrease in director’s fees and a $11,591 decrease in stock-based compensation expense.

Although we compensate our non-employee directors, in December 2008, Mr. Hudson, a non-employee director, agreed to waive payment of his monthly fees commencing January 1, 2009, and Mr. Sidhu, a non-employee director, agreed to waive payment of his fees commencing November 1, 2009.  However, each director continues to be entitled to be reimbursed for reasonable and necessary expenses incurred on our behalf.