RenovaCare, Inc. - Annual Report: 2009 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2009

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

For the transition period from ___________ to ___________

Commission file number 000-30156

ENTHEOS TECHNOLOGIES, INC.

(Exact name of registrant as specified in its charter)

(403) 444-6418

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:  

Common Stock, $0.0001 par value per share

(Title of Class)

Over The Counter Bulletin Board (OTCBB)

(Name of exchange on which registered)

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o    No x

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o    No x

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

Yes x    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date file required to be submitted and posted pursuant to Rule 405 of Regulations S-T (Section232.405 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    N/A x

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

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.   Check one:

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, based upon the closing sale price of the registrant’s common stock on June 30, 2009 as reported on the OTC Bulletin Board was $15,217,661.  Common shares held by each officer and director and by each person who owns 5% or more of the outstanding common shares have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of March 25, 2010, there were 63,075,122 shares of the registrant’s Common Stock outstanding.

Documents incorporated by reference:  None.

TABLE OF CONTENTS

ENTHEOS TECHNOLOGIES, INC.

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

PART I

Item 1.  Business.

Forward-Looking Statements 

Except for the historical information presented in this document, the matters discussed in this Form 10-K for the fiscal year ending December 31, 2009, contain forward-looking statements. Such forward-looking statements include statements regarding, among other things, (a) our projected sales and profitability, (b) our growth strategies, (c) anticipated trends in our industry, (d) our future financing plans, and (e) our anticipated needs for working capital.  Forward-looking statements, which involve assumptions and describe our future plans, strategies, and expectations, are generally identifiable by use of the words “may,” “will,” “should,” “could,” “might,” “expect,” “anticipate,” “estimate,” “believe,” “intend,” or “project” or the negative of these words or other variations on these words or comparable terminology.  This information may involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the future results, performance, or achievements expressed or implied by any forward-looking statements.  These statements may be found under “Management's Discussion and Analysis of Financial Condition and Results of Operations,”  “Business,” “Properties,” as well as in this report generally. 

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-K should be construed as a guarantee or assurance of future performance or results. Actual events or results may differ materially from those discussed in forward-looking statements as a result of various factors, including, without limitation, the risks described in this report and matters described in this report generally.  In light of these risks and uncertainties, there can be no assurance that the forward-looking statements contained in this filing will in fact occur.  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-K 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.

The Company

Incorporated under the laws of the State of Nevada, Entheos Technologies, Inc. (“Entheos” “the Company” “we” “us” and “our”) 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.

From 2002 until September 2008, through our wholly-owned subsidiary Email Solutions, Inc., we served as an Application Service Provider (“ASP”) providing outsourced email and search engine optimization services. Due to the limited success of our ASP business, management decided that it was in the best interest of our stockholders to abandon the Application Service Provider business and focus on identifying undervalued oil and gas opportunities for acquisition, development and exploration. The assets and liabilities, the results of operations and cash flows related to the ASP business were not classified as discontinued operations as the amounts were not significant. Email Solutions, Inc. was dissolved during 2008.

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. 

As we are a smaller reporting company, certain disclosures otherwise required to be made in a Form 10-K are not required to be made by us.

Description of Business

We are a small independent energy company engaged in the acquisition and development of crude oil and natural

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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 Entheos 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.

Strategy

We plan to grow our business by acquiring minority, non-operating, working interests in both currently producing wells and also by participating in workover and/or re-entry projects on previously producing proved assets or wells.  These assets will be pursued to offset the natural decline in our current production as well as provide growth in our asset portfolio over time.  Assets for acquisition will be identified through our operators, managements’ contacts in the industry as well as through the Petroleum Listing Service (“PLS”). Assets will be evaluated by management as well as by third party independent consulting engineers and geologists, having experience in the geographical areas in which the prospects are located, engaged by us on an as needed basis.  The industry professionals to be utilized by us will be contractors and will be compensated as such utilizing finder's fee agreements and consulting agreements.  

Assets for acquisition are identified through our operators, managements’ contacts in the industry as well as through the PLS. 

Acquisition of Oil & Gas Properties

In September 2008, we acquired a 21.75% working interest (16.3125% net revenue interest) in the Cooke #6 well located at the Cooke Ranch field in La Salle County, Texas which has been producing oil and gas from the Escondido formation since 2007.  In September 2008, the Company acquired a 20.00% working interest (15.00% net revenue interest) in Onnie Ray #1 Well in Lee County, Texas and the Stahl #1 Well in Fayette County, Texas which were subsequently re-entered and are producing oil and gas from the Austin Chalk formation and a 20.00% working interest (15.00% net revenue interest) in the Haile #1 Well in Frio County, Texas which is currently scheduled for re-entry operations.  On October 31, 2008 we acquired a 20.00% working interest (15.00% net revenue interest) in Pearce #1 Well in Frio County, Texas which is currently producing oil from the Austin Chalk formation. 

Capitalized costs associated with the property acquisitions are as follows:

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Geologic Background

Escondido Formation

The Escondido formation, where Cooke #6 is located, is a regional producer spanning several counties in South Texas.  There are many Escondido oil and gas fields which have produced anywhere from 600,000 to 3,100,000 barrels of oil and the gas fields have produced up to 18 BCF of gas.

Austin Chalk Formation

Giddings is a main producing field of the Austin Chalk formation consisting of fractured carbonate, which is where our Onnie Ray #1 and Stahl #1 wells are located.  This formation covers central Texas, parts of Mexico and northwest Louisiana.  The Austin Chalk in central Texas has been and continues to be explored and developed for its oil and gas potential by companies such as Anadarko Petroleum Corporation, Chesapeake Energy Corporation, and Exxon Mobil Corporation.

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

The foregoing is not necessarily indicative of the commercial viability of our properties and activities.

Production and Reserve Estimate Status

The acquisition date and production status of our oil and gas properties is summarized as follows:

The four reservoirs classified as proven developed properties is based on Securities and Exchange Commission (“SEC”) Regulation S-X Rule 4-10 “reservoirs are considered proved if economic producibility is supported by either actual production or a conclusive formation test.”  These wells are supported by actual production.  The Company has not yet obtained reserve studies providing proved reserve quantities due to the recentness of the acquisition of these properties and due to the wells still being in their initial testing phase.  Management is assessing and compiling production data to determine the need for reserves studies going forward.

The unproven property, Haile, is also classified according to guidelines set forth by SEC Regulation S-X Rule 4-10.  At the time of acquisition, the well was not supported by actual production nor were there defined engineering reserve studies.  The well 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 recompletion also resulted in no oil or gas production and the well was shut-in August 2009.  Management has impaired the well to the extent of anticipated salvage value of the equipment.

Marketing of Production

Sale of Crude Oil and Natural Gas

Our production consists of natural gas and crude that is marketed by the well site Operators.  We sell our crude oil and condensate production at or near the well-site, although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline

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and is typically committed to arrangements having a term of one year or less. We have not engaged in crude oil hedging or trading activities. We have not engaged in natural gas hedging or futures trading, nor do we have any long term contracts to sell our production.

Sales of crude oil totaled $40,437 and $8,199 for the years ended December 31, 2009 and 2008, respectively, which represents 79% and 60% of our total oil and gas revenues for the years ended December 31, 2009 and 2008, respectively.  Sales of natural gas totaled $10,697 and $5,571 for the years ended December 31, 2009 and 2008, respectively. 

Price Considerations

Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil (“NYMEX-WTI”). The average crude oil price per Bbl received by us in fiscal 2009 and 2008 was $50.16 and $71.35, respectively.

Natural gas and natural gas liquids prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our natural gas. Average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2009 and 2008 was $5.55 and $7.46, respectively.

Governmental Regulations

Our operations are affected from time to time in varying degrees by political developments and U.S. federal, state, and local laws and regulations.  In particular, natural gas and crude oil production and related operations are, or have been, subject to price controls, taxes and other laws and regulations relating to the industry.  Failure to comply with such laws and regulations can result in substantial penalties.  The regulatory burden on the industry increases our cost of doing business and affects our profitability. Although we believe we substantially comply with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted so we are unable to predict the future cost or impact of complying with such laws and regulations.

Environmental Matters

Our natural gas and crude oil exploration, development and production operations are subject to stringent U.S. federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection.  Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations to implement and enforce such laws, and compliance is often difficult and costly.  Failure to comply may result in substantial costs and expenses, including possible civil and criminal penalties. These laws and regulations may:

In addition, these laws, rules and regulations may restrict the rate of natural gas and crude oil production below the rate that would otherwise exist.  The regulatory burden on the industry increases the cost of doing business and consequently affects our profitability.  Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our financial position, results of operations and cash flows.  While we believe that we substantially comply

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with current applicable environmental laws and regulations, and we have not experienced any materially adverse effect from compliance with these environmental requirements, we cannot assure you that this will continue in the future.

The U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the present or past owners or operators of the disposal site or sites where the release occurred and the companies that transported or arranged for the disposal of the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment.  Furthermore, although petroleum, including natural gas and crude oil, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA.  State initiatives to further regulate the disposal of crude oil and natural gas wastes are also pending in certain states, and these various initiatives could have an adverse impact on us.

Stricter standards in environmental legislation may be imposed on the industry in the future.  For instance, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain exploration and production wastes as “hazardous wastes” and make the reclassified wastes subject to more stringent handling, disposal and clean-up restrictions.  Compliance with environmental requirements generally could have a materially adverse effect upon our financial position, results of operations and cash flows.  Although we have not experienced any materially adverse effect from compliance with environmental requirements, we cannot assure you that this will continue in the future.

The U.S. Federal Water Pollution Control Act (“FWPCA”) imposes restrictions and strict controls regarding the discharge of produced waters and other petroleum wastes into navigable waters.  Permits must be obtained to discharge pollutants into state and federal waters.  The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of crude oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.  Federal effluent limitations guidelines prohibit the discharge of produced water and sand, and some other substances related to the natural gas and crude oil industry, into coastal waters.  Although the costs to comply with zero discharge mandated under federal or state law may be significant, the entire industry will experience similar costs and we believe that these costs will not have a materially adverse impact on our financial condition and results of operations.  Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges.  Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans.

The U.S. Resource Conservation and Recovery Act (“RCRA”), generally does not regulate most wastes generated by the exploration and production of natural gas and crude oil.  RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.”  However, these wastes may be regulated by the EPA or state agencies as solid waste.  Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes.  Although the costs of managing solid hazardous waste may be significant, we do not expect to experience more burdensome costs than would be borne by similarly situated companies in the industry.

In addition, the U.S. Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into “waters of the United States,” a term defined to include rivers, creeks, wetlands and coastal waters, to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States.  OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill.  Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes.

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Competition

The oil and gas industry is highly competitive.  We compete with major oil companies, large and small independent companies , and individuals for the acquisition of leases and properties.  Most competitors have financial and other resources which substantially exceed ours.  Resources of our competitors may allow them to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than us.  Our ability to replace and expand our reserves is dependent on our ability to select and acquire producing properties and prospects for future drilling.

Operations

Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator’s direct expenses and monthly per well supervision fees. Per well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. We are not the operator of our wells, which are operated by Bayshore Exploration LLC and Leexus Oil LLC.  The operators charge the Company, without mark-up, for the Company’s working interest portion of the direct operating costs and overhead costs (which are comprised of administrative, supervision, office services and warehousing costs) that the operators incur with respect to our wells.

Employees

We currently have no full-time employees.  All of our activities are conducted through contracting geologists, engineers, operators and other oil and gas professionals. 

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

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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 the completion for production of an existing well bore in another formation from that in which the well has been previously completed.

“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.

Item 1A.  RISK FACTORS.

Risks Specific to Our Company

WE HAVE A HISTORY OF LOSSES WHICH MAY CONTINUE, WHICH MAY NEGATIVELY IMPACT OUR ABILITY TO ACHIEVE OUR BUSINESS OBJECTIVES.

We have very limited history with respect to our acquisition and development of oil and gas properties. In the years ended December 31, 2009 and 2008 we recorded operating losses of $639,906, and $279,447 respectively.  We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future.  Our operations are subject to the risks and competition inherent in the establishment of a business enterprise.  There can

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be no assurance that our future operations will be profitable.  Revenues and profits, if any, will depend upon various factors, including whether we will be able to continue expansion of our revenue.  We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

SINCE WE ARE IN THE EARLY STAGE OF DEVELOPMENT AND HAVE A LIMITED OPERATING HISTORY, IT MAY BE DIFFICULT FOR YOU TO ASSESS OUR BUSINESS AND FUTURE PROSPECTS.

We have only a limited history of revenues from oil and natural gas operations and have limited tangible assets. We have yet to generate positive earnings and there can be no assurance that we will ever operate profitably. With this limited operating history our company must be considered in the exploration stage. Our success is significantly dependent on a successful acquisition, drilling, completion and production program. Our operations will be subject to all the risks inherent in the establishment of a developing enterprise and the uncertainties arising from the absence of a significant operating history. We may be unable to locate recoverable reserves or operate on a profitable basis. We are in the exploration stage and potential investors should be aware of the difficulties normally encountered by enterprises in the exploration stage. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in our company.

BECAUSE WE ARE SMALL AND DO NOT HAVE MUCH CAPITAL, WE MAY HAVE TO LIMIT OUR DEVELOPMENT AND PRODUCTION ACTIVITY WHICH MAY RESULT IN A LOSS OF YOUR INVESTMENT.

Because we are small and do not have much capital, we must limit our oil and gas acquisition, development and production activity. As such we may not be able to complete an exploration program that is as thorough as we would like. In that event, existing reserves may go undiscovered. Without finding reserves or acquiring additional reserves, we cannot generate revenues and you will lose your investment.

AS OUR PROPERTIES ARE IN THE EXPLORATION STAGE, THERE CAN BE NO ASSURANCE THAT WE WILL ESTABLISH COMMERCIAL DISCOVERIES ON OUR PROPERTIES.

Exploration for economic reserves of oil and gas is subject to a number of risk factors. Few wells that are ultimately reworked are capable of producing commercially viable quantities of oil and or gas for any extended period of time.  If the wells in which we have an interest do not produce commercially viable amounts of oil or gas or cease to produce such quantities after being reworked we may need to curtail or cease our operations.

THE POTENTIAL PROFITABILITY OF OIL AND GAS VENTURES DEPENDS UPON FACTORS BEYOND THE CONTROL OF OUR COMPANY.

The potential profitability of oil and gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. In addition, adverse weather conditions can also hinder drilling operations. These changes and events may materially affect our financial performance. These factors cannot be accurately predicted and the combination of these factors may result in our company not receiving an adequate return on invested capital.

WE MAY FAIL TO FULLY IDENTIFY PROBLEMS WITH ANY PROPERTIES WE ACQUIRE.

Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify.

THE OIL AND GAS INDUSTRY IS HIGHLY COMPETITIVE AND THERE IS NO ASSURANCE THAT WE WILL BE SUCCESSFUL IN ACQUIRING OIL AND GAS INTERESTS OR LEASES.

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including

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many major oil and gas companies, which may have substantially greater technical, financial and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases, suitable properties for drilling operations and necessary drilling equipment, as well as for access to funds. We cannot predict if the necessary funds can be raised or that any projected work will be completed or additional oil and gas interests acquired.

Risks Specific to Our Industry

OIL AND GAS OPERATIONS ARE SUBJECT TO COMPREHENSIVE REGULATION WHICH MAY CAUSE SUBSTANTIAL DELAYS OR REQUIRE CAPITAL OUTLAYS IN EXCESS OF THOSE ANTICIPATED CAUSING AN ADVERSE EFFECT ON OUR COMPANY.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages. To date we have not been required to spend any material amount on compliance with environmental regulations.

However, we may be required to do so in future and this may affect our ability to expand or maintain our operations.

EXPLORATION AND PRODUCTION ACTIVITIES ARE SUBJECT TO CERTAIN ENVIRONMENTAL REGULATIONS WHICH MAY PREVENT OR DELAY THE COMMENCEMENT OR CONTINUANCE OF OUR OPERATIONS.

In general, our exploration, development and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry. We believe that our operations comply, in all material respects, with all applicable environmental regulations. Our operating partners maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks.

EXPLORATORY DRILLING INVOLVES MANY RISKS AND WE MAY BECOME LIABLE FOR POLLUTION OR OTHER LIABILITIES WHICH MAY HAVE AN ADVERSE EFFECT ON OUR FINANCIAL POSITION.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor, and other risks are involved. We may become subject to liability for pollution or hazards against which we cannot adequately insure or which we may elect not to insure. Incurring any such liability may have a material adverse effect on our financial position and operations.

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Item 2.  properties.

We do not own any properties other than oil and gas properties acquired during 2008.  On September 10, 2008 we entered into a one year operating lease agreement with a non-affiliate for our corporate office, located at 888 3rd Street SW, Suite 1000, Calgary, AB   Canada T2P 5C5.  Upon the completion of the one year lease agreement, the lease automatically converted to a month to month based contract. The monthly rent is $315 CDN.

Item 3.  Legal proceedings.

We are currently not a party to any material pending legal proceedings or government actions, including any bankruptcy, receivership, or similar proceedings. In addition, management is not aware of any known litigation or liabilities involving the operators of our properties that could affect our operations. Should any liabilities incur in the future, they will be accrued based on management’s best estimate of the potential loss. As such, there is no adverse effect on our financial position, results of operations or cash flow at this time. Furthermore, we do not believe that there are any proceedings to which any of our directors, officers, or affiliates, any owner of record of the beneficially or more than five percent of our common stock, or any associate of any such director, officer, affiliate, or security holder is a party adverse or has a material interest adverse to us.

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ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Our Annual Meeting of Stockholders (the “Annual Meeting”) was held on December 14, 2009, at which time the stockholders voted on the following proposals:

1.             The election of a board of directors to serve until the next Annual Meeting or until their respective successors is duly elected and has been qualified. 

2.             Ratifying the appointment of Peterson Sullivan LLP as our auditors for the fiscal year ending December 31, 2009.

                    Votes For                               Votes Against                       Votes Abstained

                                32,700,242                                 6,562                                        1,202

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PART II

ITEM 5.        MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. 

Market Information

Our Common Stock is listed on the Over the Counter Bulletin Board (“OTCBB”) under the symbol "ETHT". The following table sets forth the high and low sale prices for the periods indicated:

As of March 22, 2010, there were approximately 320 stockholders of record.

Dividend Policy

We have not paid any dividends on our common stock and our board of directors presently intends to continue a policy of retaining earnings, if any, for use in our operations. The declaration and payment of dividends in the future, of which there can be no assurance, will be determined by the board of directors in light of conditions then existing, including earnings, financial condition, capital requirements and other factors. The Nevada Revised Statutes prohibit us from declaring dividends where, if after giving effect to the distribution of the dividend:

·         We would not be able to pay our debts as they become due in the usual course of business; or

·         Our total assets would be less than the sum of our total liabilities plus the amount that would be needed to satisfy the rights of stockholders who have preferential rights superior to those receiving the distribution.

Except as set forth above, there are no restrictions that currently materially limit our ability to pay dividends or which we reasonably believe are likely to limit materially the future payment of dividends on common stock.

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Securities Authorized for Issuance Under Equity Compensation Plans

                                                                                Number of securities

                                                                                                                                                                remaining available for

                                                Number of Securities to          Weighted-average exercise      future issuance under

                                                be issued upon exercise of      price of outstanding                 equity compensation plans

                                outstanding options,                options, warrants and              (excluding securities

                                warrants and rights                  rights                                       reflected in column (a))

Plan Category                                          (a)                                            (b)                                           (c)

_____________________________________________________________________________________________

Equity compensation plans

approved by security holders                  150,000(1)                                              $1.00                       119,850,000

Equity compensation plans not

approved by security holders 

_____________________________________________________________________________________________

Total                                                        150,000 (1)                                             $1.00                       119,850,000

(1)     50,000 were granted to our former CFO and were cancelled following his resignation on January 9, 2009.

ITEM 7.        MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Discussion and Analysis

The following discussion and analysis is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States, and should be read in conjunction with our financial statements and related notes. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. Management bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. In addition, the following discussion and analysis contains forward-looking statements that involve risks and uncertainties, including, but not limited to, those discussed in “Forward Looking Statements,” and elsewhere in this Form 10-K.

Our Oil and Gas Interests

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

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with oil and gas properties as of December 31, 2009 is summarized as follows:

The Company did not acquire any additional interests in oil and gas properties during 2009.  The additions to capitalized costs relating to oil and gas properties is due to recording an asset retirement obligation as of December 31, 2009, continued completion efforts on our unproven property well, Haile #1, and equipment replacements on the Onnie Ray #1 well. 

The Company recorded an impairment loss of $335,894 and $93,444 for the years ended December 31, 2009 and 2008, respectively.  The impairment recognized during 2009 was due to a decline in oil and natural gas prices in the first half of the year; lower than expected production volumes obtained from our oil and gas wells, the shut-in of an unproven property, Haile #1, and utilizing a 12-month average beginning-of-the-month price instead of a period-end price.  The impairment is similar to amortization and therefore is not added to the cost of properties being amortized.

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. Management has impaired the well to the extent of anticipated salvage value of the equipment and recorded an asset retirement obligation as of year end 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 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-

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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 December 31, 2009, 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 $335,894 and $93,444 during 2009 and 2008, 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

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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 liability is allocated to operating expense using a systematic and rational method.

Asset retirement obligations amounted to $50,000 as of December 31, 2009.

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” in the Notes to Financial Statements.

Recently Adopted Accounting Guidance

In December 2008, the SEC issued release 33-8995 “Modernization of Oil and Gas Reporting.” This rule revises some of the oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act and the Securities Exchange Act of 1934, as well as Industry Guide 2. Effective December 31, 2009, the FASB issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. Definitions were updated to be consistent with the Petroleum Resource Management System. Additionally, this new guidance requires that entities use a 12-month average beginning-of-the-month price when calculating the quantities of proved reserves and performing the full-cost ceiling test calculation.  Other key revisions were the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. We adopted this guidance as of December 31, 2009 without material impact on our financial statements as we have no proved reserves.

In January 2010, the FASB issued new authoritative guidance for Oil and Gas Reserve Estimation and Disclosures.  The guidance is  designed to improve the reserve estimation and disclosure requirements by: (a) updating the reserve estimation requirements for recent changes in practice and technology; and (b) expanding the disclosure requirements for equity method investments.  We adopted this guidance as of December 31, 2009 without material impact on its financial statements as we have no proved reserves.

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 business plan, 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.

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2009 Results of Operations

Oil and Gas Revenues

Total oil and gas revenues increased 271% from $13,770 in 2008 to $51,134 in 2009 due to a full year of production in 2009 compared to approximately 2.75 months of production in 2008 as our wells came on-line. Average daily production on an equivalent basis for 2009 was 3.1 BOE and was 2.9 BOE for 2008 representing an increase of 7%.  Oil represented 72% of our production mix in 2009 compared to 48% in 2008 primarily due to our largest oil producing well, Pearce #1, beginning production in mid-December 2008.  Gas production on an equivalent annual basis in 2009 was lower than anticipated due to a tubing puncture in the Onnie Ray well in Q1 of 2009.  The puncture is scheduled for repair in the first quarter 2010. 

Oil production during 2009 totaled 806.1 barrels and generated $40,437 in revenues compared to 113.9 barrels and $8,199 in revenues in 2008. This increase is due to a full year of production in 2009 compared to 2.75 months of

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production in 2008 as our wells came on-line. Average oil prices realized in 2009 were $51.16 per barrel compared to $71.98 per barrel in 2008 representing a 30% decrease due to lower oil and gas pricing.

Gas production during 2009 totaled 1,927.0 Mcf and generated $10,697 in revenues compared to 746.6 Mcf and $5,571 in revenues during the same period in 2008 representing a 158% increase in production and a 63% increase in revenue. This increase is due to a full year of production in 2009 compare to 2.75 months of production in 2008 as our wells came on-line. Average gas prices realized for 2009 were $5.55 per Mcf compared to $7.46 per Mcf in 2008 representing a 25% decrease due to lower gas pricing. 

Lease Operating Expenses

Lease operating expenses for 2009 increased by 373% to $42,984 compared to $9,080 for 2008. The increase is due to a full year of production in 2009 compared to 2.75 months of production in 2008.  Lease operating expenses on an equivalent basis were effectively flat from 2008 for $38.10 to 2009 for $38.13. 

Impairment of Oil and Gas Properties

The impairment of oil and gas properties increased in 2009 to $335,894 from $93,444 for 2008 representing an increase of 259%.  The increase in the impairment was due to a decline in oil and natural gas prices in the first half of the year, lower than expected production volumes obtained from our oil and gas wells, the shut-in of an unproven property, and the adoption of new accounting standards utilizing a 12-month average beginning-of-the-month price instead of a period-end price.

Management Fees

Management fees increased in 2009 to $94,550 from $54,359 in 2008 representing an increase of 74%.  The $40,190 increase is comprised of an increase of $15,435 in director’s fees and an increase of $24,755 in stock-based compensation expense.  This increase is due to increasing fees paid to directors in September 2008 from $200 per quarter to approximately $2,000 per month and to recognizing a full year of stock compensation expense in 2009 for the stock granted in September 2008. 

Accounting and Legal Fees

Accounting and legal expenses increased in 2009 to $182,004 from $95,168 in 2008 representing an increase of 91%.  The $86,836 increase is comprised of an increase in auditor and tax preparation fees for $32,936, and an increase in outsourced accounting fees of $42,625 and an increase in legal fees of $11,275 due to an increase in registration statements filed with the SEC.

Change in Fair Value of Warrant Liability

During 2009, we began to account for the Series A and the Series B Warrants as derivatives.  We determined that our Series A and Series B warrants contained a Dilutive Issuance provision. As a result, we reclassified a total of 12,900,000 warrants from equity to a noncurrent warrant liability and recorded a cumulative effect of change in accounting principle that reduced our accumulated deficit as of January 1, 2009 by $1,624,513.

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 $309,215 and a non-cash gain of $565,891 (net gain of $1,909,455) relating to the Series A and Series B Warrants, respectively, for the year ended December 31, 2009.

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Liquidity and Capital Resources

We had cash and cash equivalents of $2,409,770 and $2,734,591 as of  December 31, 2009 and December 31, 2008, respectively. We have financed our operations from cash on hand during the year ended December 31, 2009. 

Net cash flows used in operating activities was ($290,976) for the year ended December 31, 2009, compared to net cash used in operating activities of ($69,687) for the year ended December 31, 2008.

Cash used in investing activities was ($33,845) for the year ended December 31, 2009, compared to cash used in investing activities of ($442,028) for the year ended December 31, 2008.  The cash used in 2009 represents additions to capitalized costs of oil and gas properties and the cash used in 2008 represent acquisitions of oil and gas properties.

We had no cash used or generated in financing activities for the year ended December 31, 2009, compared to cash generated from financing activities of $3,200,000 for the year ended December 31, 2008.

The accompanying financial statements have been prepared assuming we will continue as a going concern. We have incurred cumulative losses of $4,438,001 through December 31, 2009.  Additionally, we have expended a significant amount of cash to acquire working interests in oil and gas properties and operating as a public entity. We expect to continue to incur losses from business operations in the future. Management believes that our cash and cash equivalent balances, anticipated cash flows from operations and other external sources of credit will be sufficient to meet our cash requirements through December 2011 if not longer. Our prospects after December 2011 will depend in large part on our ability to successfully raise capital from external sources to pay for planned expenditures and to fund operations.

Due to the "start up" nature of our business, we expect to incur losses as we expands. We expect to raise additional funds through private or public equity investment in order to expand the range and scope of our business operations. We will seek access to private or public equity but there is no assurance that such additional funds will be available for us to finance our operations on acceptable terms, if at all.

At this time, we have no agreements or understandings with any third party regarding any financings.

Moreover, the trading price of our shares of common stock and a downturn in the United States stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, or experience unexpected cash requirements that would force us to seek alternative financing. Further, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our shares of common stock. If additional financing is not available or is not available on acceptable terms, we will have to curtail our operations.

Related Party Transactions

Executive Management: For the years ended December 31, 2009 and December 31, 2008, we incurred $30,000 and $10,000, respectively, in fees paid to Derek Cooper our President, Chief Executive Officer and Chief Financial Officer. In addition, we recorded $14,474 and $4,840 as stock compensation expense (refer to “Note 6. Stock Options” in the Notes to Financial Statements) for the years ended December 31, 2009 and December 31, 2008, respectively.

Director Fees: For the years ended December 31, 2009 and December 31, 2008, we incurred $50,435 and $25,000, respectively, in board fees for non-employee directors. In addition, we recorded $29, 640 and $14,520 as stock compensation expense (refer to “Note 6. Stock Options” in the Notes to Financial Statements) for the years ended December 31, 2009 and December 31, 2008, respectively.

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Off Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Recent Accounting Pronouncements

See "Note 2. Accounting Policies" in the Notes to Financial Statements in this Form 10-K.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Entheos Technologies, Inc.

Calgary, Alberta

We have audited the accompanying balance sheets of Entheos Technologies, Inc. ("the Company") as of December 31, 2009 and 2008, and the related statements of operations, stockholders' equity, and cash flows for the years then ended.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Entheos Technologies, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.

/S/ PETERSON SULLIVAN LLP

Seattle, Washington

March 31, 2010

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ENTHEOS TECHNOLOGIES, INC.

NOTES TO FINANCIAL STATEMENTS

FOR THE YEAR ENDED DECEMBER 31, 2009

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 interest are producing. The Company currently 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.

From 2002 until September 2008, through our wholly-owned subsidiary Email Solutions, Inc., we served as an Application Service Provider (“ASP”).   Due to the limited success of our ASP business, management decided that it was in the best interest of our stockholders to abandon the Application Service Provider business and focus on identifying undervalued oil and gas opportunities for acquisition, development and exploration. The assets and liabilities, the results of operations and cash flows related to the ASP business were not classified as discontinued operations as the amounts were not significant.  Email Solutions, Inc. was dissolved during 2008.

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. Accounting Policies

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 consolidated financial statements.

Principles of Accounting

These financial statements have been prepared by management in accordance with US GAAP.

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.

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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.

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 December 31, 2009, 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. As a result of this analysis and lack of proved reserves, the Company recorded an impairment loss of $335,894 and $93,444 during 2009 and 2008, 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. 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

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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 liability is allocated to operating expense using a systematic and rational method.

Asset retirement obligations amounted to $50,000 at December 31, 2009.

Fair Value of Financial Instruments

The determination of fair value of financial instruments is made at a specific point in time, based on relevant information about financial markets and specific financial instruments.  As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision.  Changes in assumptions can significantly affect estimated fair values.  The carrying value of cash and cash equivalents, accounts payable and accrued liabilities, and accounts payable – related parties approximates their fair value because of the short-term nature of these instruments.

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.”

Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents.  The Company did not have any cash equivalents at December 31, 2009 and 2008.  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.

Warrant Liability Derivative

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

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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.

Income Taxes

We recognize income taxes on an accrual basis based on tax position taken or expected to be taken in our tax returns.  A tax position is defined as a position in a previously filed tax return or a position expected to be taken in a future tax filing that is reflected in measuring current or deferred income tax assets and liabilities.  Tax positions are recognized only when it is more likely than not (i.e., likelihood of greater than 50%), based on technical merits, that the position would be sustained upon examination by taxing authorities.  Tax positions that meet the more likely than not threshold are measured using a probability-weighted approach as the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement.  Income taxes are accounted for using an asset and liability approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in our financial statements or tax returns.  A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized.  Should they occur, our policy is to classify interest and penalties related to tax positions as interest expense.  Since our inception, no such interest or penalties have been incurred.

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.

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

In June 2009, the FASB issued new authoritative guidance to eliminate the quantitative approach previously required for determining the primary beneficiary of a variable interest entity and requires ongoing qualitative reassessments of whether an enterprise is the primary beneficiary of a variable interest entity.  We adopted the guidance in 2009 without material impact on our consolidated financial statements.

In April 2009, the FASB issued additional authoritative guidance on the fair value of financial instruments, which provides: (i) further provisions on estimating fair value when the markets become inactive and quoted prices reflect

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distressed transactions; (ii) extended disclosure requirements for interim financial statements regarding the fair value of financial instruments; and (iii) new criteria for recording impairment charges on investments in debt instruments.  We adopted the guidance on a prospective basis in 2009 without material impact to our financial statements.

In June 2008, the FASB ratified new authoritative guidance addressing the accounting for certain instruments (or embedded features) determined to be indexed to an entity’s own stock. This guidance provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions.  We adopted this guidance effective January 1, 2009 on a prospective basis.  See “Note 5. Stockholders’ Equity” for further discussion of the impact of this guidance to our financial statements.

In January 2010, the FASB issued new authoritative guidance regarding the disclosure of fair value measurements, which clarifies certain existing disclosure requirements as well as requiring new disclosures related to significant transfers between each fair value level as well as requiring additional information about Level 3 activity.  This guidance begins phasing in during the first fiscal period after December 15, 2009.  We do not expect the implementation of this guidance to have a material impact on our financial statements.  

In May 2009, the FASB issued new authoritative guidance for the accounting for and disclosures of subsequent events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  The guidance was effective for interim or annual financial periods ending after June 15, 2009.  This guidance applies to both interim financial statements and annual financial statements.  In February 2010, the FASB issued additional guidance that clarifies certain existing evaluation and disclosure requirements related to subsequent events.  We adopted the initial and revised guidance without material impact on our financial statements.

In December  2008, the SEC issued release 33-8995 “Modernization of Oil and Gas Reporting.” This rule revises some of the oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act and the Securities Exchange Act of 1934, as well as Industry Guide 2. Effective December 31, 2009, the FASB issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. Definitions were updated to be consistent with the Petroleum Resource Management System. Additionally, this new guidance requires that entities use a 12-month average beginning-of-the-month price when calculating the quantities of proved reserves and performing the full-cost ceiling test calculation.  Other key revisions the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The Company adopted this guidance as of December 31, 2009 without material impact on its financial statements as the Company has no proved reserves.

In January 2010, the FASB issued new authoritative guidance for Oil and Gas Reserve Estimation and Disclosures.  The guidance is designed to improve the reserve estimation and disclosure requirements by: (a) updating the reserve estimation requirements for recent changes in practice and technology; and (b) expanding the disclosure requirements for equity method investments.  The Company adopted this guidance as of December 31, 2009 without material impact on its financial statements as the Company has no proved reserves.

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

Dilutive common stock equivalents include 13,050,000 and 13,100,000 warrants and stock options that are not included in the computation of diluted loss per share because to do so would be anti-dilutive for 2009 and 2008, respectively.  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 loss per share for the years ended December 31, 2009 and 2008:

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Note 4. Oil and Gas Properties

As of December 31, 2009, the Company owned non-operating, working interests in five wells in one geographic area as follows:

Net capitalized costs associated with these oil and gas properties as of December 31, 2009 and 2008 is summarized as follows:

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Costs incurred in oil and gas property acquisition, exploration and development activities, are summarized as follows at December 31, 2009:

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 at December 31, 2009, and 2008 there were no capitalized costs subject to amortization.

Unproven properties costs as of December 31, 2009 and 2008 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. 

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 $335,894 and $93,444 for the years ended December 31, 2009 and 2008, respectively.  The impairment recognized during 2009 was due to a decline in oil and natural gas prices in the first half of the year; lower than expected production volumes obtained from our oil and gas wells; and utilizing a 12-month average beginning-of-the-month price instead of a period-end price.  The impairment is similar to amortization and therefore 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:

The change in estimated obligations represents the Company’s initial recognition of retirement obligations related to oil and gas properties. 

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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).  The relative fair value of the common stock was estimated to be $1,571,638 and the relative fair value of the warrants was estimated to be $1,653,362 as determined based on the relative fair value allocation of the proceeds received. The warrants were valued on the transaction date using the Black-Scholes option pricing model using the following assumptions: expected dividend yield of 0%, risk-free interest rate of 2.4% - 2.6%, volatility of 96.15% - 100.76%, and contractual lives of 1.5 – 2 years.

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 years ended December 31, 2009 and 2008.

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 December 28, 2010 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 December 31, 2009, 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

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material impact on the fair value estimate of the warrant liability at December 31, 2009 as it relates to the Series A or Series B Warrants.

At December 31, 2009, the Company valued the warrant liability using a Black-Scholes model (Level 3 inputs) containing the following assumptions: