Hero Technologies Inc. - Quarter Report: 2010 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

———————

FORM 10-Q

———————

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

For the quarterly period ended June 30, 2010

OR

¨ TRANSITION REPORT PURSUANT TO 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

Commission File Number: 000-52419

———————

HOLLOMAN ENERGY CORPORATION

(Exact Name of Issuer as Specified in Its Charter)

———————

333 North Sam Houston Parkway East, Suite 600, Houston, Texas     77060

(Address of Issuer's Principal Executive Offices)  (Zip Code)

Issuer’s telephone number:  (281) 260-0193

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) had been subject to such filing requirements for the past 90 days.  Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 Yes ¨     No ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act).  Yes ¨ No þ

PART I FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

CONSOLIDATED BALANCE SHEETS

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

2

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

3

HOLLOMAN ENERGY CORPORATION

(A Exploration Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

4

HOLLOMAN ENERGY CORPORATION

(A Exploration Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(Unaudited)

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

5

HOLLOMAN ENERGY CORPORATION

(An Exploration Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

1.

BASIS OF PRESENTATION

Unaudited Interim Consolidated Financial Statements

The unaudited interim financial statements of Holloman Energy Corporation (the “Company”) have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and the rules and regulations of the Securities and Exchange Commission (“SEC”). They do not include all information and footnotes required by GAAP for complete financial statements. However, except as disclosed herein, there have been no material changes in the information disclosed in the notes to the financial statements for the year ended December 31, 2009 included in the Company’s Annual Report on Form 10-K/A, filed with the SEC. The interim unaudited financial statements should be read in conjunction with those financial statements included in the Form 10-K/A. In the opinion of management, all adjustments considered necessary for fair presentation, consisting solely of normal recurring adjustments, have been made. Operating results for the three and six month periods ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

Recent Accounting Pronouncements

The Company has reviewed recently issued accounting pronouncements and plans to adopt those that are applicable to it. It does not expect the adoption of these pronouncements to have a material impact on its financial position, results of operations or cash flows.

2.

OIL AND GAS PROPERTIES

The Company’s oil and gas properties are located in Australia and are unproven. As such, the costs capitalized in connection with those properties are not currently subject to depletion.

The Company has a 66.67% working interest in two licenses (PEL 112 and PEL 444) located in the Cooper/Eromanga Basin, in the State of South Australia.

On June 11, 2008 the Australian government consolidated two of the Company’s oil and gas licenses (PEL 108 and PEL 109) into one license (PEL 444). In connection with that consolidation, the government also extended the license term and associated work programs for PEL 444 and PEL 112 by five years.

The Company is currently party to a contingent agreement with Holloman Oil & Gas Limited (“HOG”), an Australian corporation, which potentially grants HOG its working interest in PEL 112. To earn its working interest, HOG agreed to:

·

Fund the costs required to drill, and if warranted, complete three wells on PEL 112 within the timeframes required by the permit work programs; and

·

Pay the Company a 1.33% overriding royalty on gross revenues generated from the sale of any oil or gas produced from wells drilled on the PEL 112.

6

In the event the agreement is pursued, the Company has the right to earn up to a 33.33% working interest in the PEL 112 license by paying, prior to the time any well has reached 50% of the expected total depth, the Company’s proportionate share of the cost of drilling any of the wells involved in the three-well drilling program. The Company also has the right to earn up to a one-third working interest in any future wells drilled on the PEL 112 by paying its proportionate share of the cost of drilling. Two of the Company’s officers/directors are officers and/or directors and shareholders in Holloman Corporation, which holds a 100% interest in HOG.

On August 28, 2009 the Company retained Macquarie Tristone (“Tristone”) to assist in finding a joint venture partner to share all or part of its costs of exploring and developing its Cooper/Eromaga Basin licenses. The Company has no obligation to accept any transaction proposed by Tristone. The Company agreed to pay Tristone a non-refundable retainer of CAD$50,000 (USD$47,900) and CAD$50,000 in fees per month for a minimum and maximum of four months (total work fees USD$189,900). During the six month period ended June 30, 2010, the Company incurred CAD$200,000 (USD$192,607) in fees to Tristone. The Company will also pay Tristone success fees ranging between CAD$800,000 and CAD$1,000,000 if Tristone is successful in arranging an acceptable transaction(s).  All fees paid to date are creditable against success fees, if success fees are incurred.

3.

STOCK-BASED COMPENSATION

During the six and three month periods ended June 30, 2010 the Company recognized $758,421 and $379,211, respectively, of non-cash compensation expense related to non-vested share-based compensation under its 2009 Non-Qualified Stock Option Plan (the “Option Plan”). As of June 30, 2010, $504,541 of total unrecognized compensation cost remains under the Option Plan. Of this amount, $307,706 is expected to be recognized during the remainder of 2010, and $196,835 during 2011.

7

FORWARD LOOKING STATEMENTS

The information contained in this Form 10-Q contains certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve risks and uncertainties, including among other things, statements regarding our capital needs, business strategy and expectations. Any statement which does not contain a historical fact may be deemed to be a forward-looking statement. In some cases, you can identify forward-looking statements by terminology such as "may", "will", "should", "expect", "plan", "intend", "anticipate", "believe", "estimate", "predict", "potential" or "continue", the negative of such terms or other comparable terminology. In evaluating forward looking statements, you should consider various factors outlined in our latest Form 10-K/A, filed with Securities Exchange Commission on April 1, 2010, and, from time to time, in other reports we file with the U.S. Securities and Exchange Commission. These factors may cause our actual results to differ materially from any forward-looking statement. We disclaim any obligation to publicly update these statements, or disclose any difference between our actual results and those reflected in these statements.

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and plan of operations should be read in conjunction with our unaudited financial statements and related notes included as part of this report and our Form 10-K/A, for the year ended December 31, 2009 filed with Securities Exchange Commission on April 1, 2010.

Holloman Energy Corporation (“we” or the “Company”) was incorporated in Nevada on May 14, 2004. Between May 2004 and May 2007 we were relatively inactive.

The acquisition and disposal of Endeavor Canada

On August 3, 2007 we acquired Endeavor Canada, an Alberta corporation involved in the exploration and development of oil and gas, for 9,000 shares of our Series A Preferred stock and 9,000,000 shares of the Class A Preferred stock of our wholly owned subsidiary, First Endeavor Holdings. Cameron King, one of our former officers and directors, owned a controlling interest in Endeavor Canada at the time of this transaction and received 6,500 Series A Preferred shares and 6,500,000 First Endeavor Holdings Class A Preferred shares in exchange for his shares in Endeavor. For accounting purposes, our acquisition of Endeavor Canada constituted a recapitalization and the acquisition was accounted for similar to a reverse merger whereby we were deemed to have been acquired by Endeavor Canada.

During January 2008, we determined that the oil and gas assets held by Endeavor Canada did not warrant further investment. On February 15, 2008 we sold our interest in Endeavor Canada to Cameron King. As part of the consideration for the purchase, the 6,500 shares of our Series A Preferred stock and the 6,500,000 Class A Preferred shares of First Endeavor Holdings previously issued to Mr. King were returned to us and cancelled. At the time of the sale, the assets of Endeavor Canada included all of our Canadian oil and gas properties.

Oil and gas properties

In May 2007 we acquired a 62.5% working interest in an offshore Australian oil and gas exploration permit area known as Victoria Permit 60 (“Vic P60”). We paid $639,487 in cash plus a 4.00% overriding royalty participation for this interest.

On November 21, 2007 we acquired Holloman Petroleum Pty. Ltd. (“Holloman Petroleum”) for 18,600,000 shares of our common stock with a fair market value of $15,903,000.  At the time of purchase, Holloman Petroleum’s assets consisted of working interests, varying between 37.5% and 100%, in seven oil and gas permits awarded by the Australian government. These permits, which had remaining terms expiring between October 2010 and June 2013, covered 4,554 square kilometers (1,125,317 acres) of land in the Cooper/Eromanga Basin and 2,589 square kilometers (639,755 acres) offshore in the Gippsland Basin and the Barrow Sub-Basin.

8

Onshore licenses –Cooper Basin

We hold working interests of 66.67% in two onshore Petroleum Exploration Licenses (PELs) in Australia. PEL 112 is comprised of 2,196 square kilometers (542,643 gross acres). PEL 444, which resulted from the consolidation of the PEL 108 and PEL109 permits, is comprised of 2,358 square kilometers (582,674 gross acres). Both licenses are located on the southwestern flank of the Cooper Basin in the State of South Australia. We are obligated to pay 4.46% in royalties on our revenues generated by operations on these licenses.

The Department of Primary Industries and Resources of South Australia reports that the Cooper Basin has sourced over 4 billion barrels of oil and 5 trillion cubic feet of recoverable gas. It has in excess 120,000 kilometers of 2-D seismic data and more than 1,200 wells in 65 oil and 20 gas fields. Our management believes that Australia provides a stable regulatory, tax and business environment in the oil and gas sector.

On March 7, 2008 we entered into a contingent agreement with Holloman Oil & Gas Limited (“Holloman Oil & Gas”). If pursued, the agreement grants Holloman Oil & Gas the right to earn a two-thirds working interest in PEL 112. To earn this working interest, Holloman Oil & Gas agreed to:

1.

Fund the costs required to drill, and if warranted, complete three wells on the PEL 112 within the timeframes required by the permit work program; and

2.

Pay us a 1.33% overriding royalty on gross revenues generated from the sale of any oil or gas produced from wells drilled on the PEL 112.

Under the contingent agreement, we would have the right to earn up to a one-third working interest in the PEL 112 concession by paying, prior to the time any well has reached 50% of the expected total depth, our proportionate share of the cost of drilling any of the wells involved in the three-well drilling program. We would also have the right to earn up to a one-third working interest in any future wells drilled on the PEL 112 (over and above the initial three-well drilling program) by paying our proportionate share of the cost of drilling the wells.

In March 2008 Holloman Oil & Gas drilled an exploratory well on PEL 112. The well was drilled to approximately 6,000 feet and was a dry hole.

In June 2008 the Australian government extended the license term and associated work programs for PEL 444 and PEL 112 by five years. Under Australian Law, at the end of each five year term, one third of the area covered by a petroleum exploration license must be relinquished. During June 2008, we identified and relinquished one-third of the acreage covered by PEL 112 and PEL 444 to the Australian government.

To maintain our exploration rights in the Cooper/Eromanga Basin, the Australian Government requires that we fulfill the following minimum work commitments:

The farmin agreement through which we hold our working interests in PEL 112 and PEL 444 also obligates us to fulfill the drilling commitment established by the Australian Government. Based on technical recommendations, we intend to pursue the acquisition of a combination of 3D and 2D seismic data on our licenses. Our current exploration plan also calls for the drilling of more than the two wells required by the minimum work program.

9

During 2010, we substantially completed processing of more than 666 km (414 miles) of 2D seismic data. This reprocessing fulfilled our June 11, 2010 work program requirements and covered a significant portion of PEL 112 and PEL 444. Our 2D seismic reprocessing was performed by Dayboro Geophysical Pty Ltd (“Dayboro”) under the supervision of Isis Petroleum Consultants Pty Ltd (“Isis”). Both Isis and Dayboro are independent engineers with geological and geophysical expertise and lengthy work experience in the Cooper Basin. The processing sequence targeted lines which complimented our technical assessment of likely drilling prospects and future seismic acquisition.

We have also completed a broad range of technical studies relating to PEL 112 and PEL 444. The studies were performed by Isis and included; a) a review of Cooper Basin exploration acreage (including an analysis of the chronostratigraphy, an assessment of neighboring exploration results, an analysis of petroleum systems and a probabilistic volumetric assessment of leads), b) oil migration studies, c) adjacent oil pools studies, and d) economic feasibility studies. In the opinion of management, the results of the studies has increased the prospectivity of both licenses.

Heavy rains beginning in February 2010, created wide scale flooding in the Cooper Basin. The inaccessibility of roads and facilities has partially curtailed Cooper Basin oil production and resulted in a general contraction of exploration activity. Flood waters have begun to recede, but exploration within substantial areas of the Basin remains temporarily impractical. We understand that the receding of the flood waters will likely result in access to PEL112 prior to access to PEL 444. We continue the necessary steps to obtain “Work Area Clearances” and plan for the acquisition of additional targeted 3D and 2D seismic data on these licenses.

During the 2010 license year, we retained Macquarie Tristone (“Tristone”) to assist us in finding a joint venture partner to share all, or part, of the costs of exploring and developing our Cooper Basin concessions. In connection with that search, Tristone prepared and managed data rooms presenting technical, environmental and economic information related to our Cooper Basin holdings. We received multiple offers or firm expressions of interest from potential joint venture partners as a result of this process. We are currently finalizing discussions related to the  interest generated to determine which, if any, are acceptable to us. We believe the results and timing of our joint venture negotiations have been negatively affected by the flooding.

During 2009, we actively sought joint venture partners for our oil and gas concessions and pursued financing to support seismic acquisition in the Cooper/Eromanga Basin. During 2010, we anticipate the establishment of one or more joint ventures, obtaining additional capital, and the pursuit of our Cooper Basin exploration plan.

Offshore permits – Gippsland Basin and Barrow Sub-Basin

In May 2007 we acquired a 62.5% working interest in an offshore Australian oil and gas exploration permit area known as Victoria Permit 60 (“Vic P60”). In connection with our acquisition of Holloman Petroleum we acquired the remaining 37.5%, working interest in that permit. The Barrow Sub-Basin permits were also acquired through our acquisition of Holloman Petroleum.

The Vic P60 permit obligated us to drill a deep-sea exploration well by October 28, 2010. The Barrow Sub-Basin permits (WA-372P, WA-373P and WA-395P) required us to drill 12 offshore exploration wells between June 2010 and June 2013. Both the Barrow and Vic P60 permits also required the acquisition of significant amounts of 3D seismic data. Early estimates indicated the costs to perform the required work on the Barrow and Vic P60 permits would be in excess of $220,500,000.

Despite our best efforts, we were unable to identify a joint venture partner willing to undertake the obligations associated with those permits, and felt it unlikely that we could do so in the current economic climate. Our work requirements to hold the permits had fallen behind schedule. Further, we recognized that continued pursuit of these permits would detract from our ability to maximize the value of our Cooper/Eromanga Basin holdings. As a result, we determined that it was in our best interest to relinquish our exploration rights in our offshore permits.

On June 18, 2009 we requested procedural advice from the Australian government concerning relinquishment of our Barrow Sub-Basin permits. On August 5, 2009 the government returned a Notice of Intent to Cancel those permits. On October 16, 2009 the permits were cancelled.

10

On December 28, 2009 we requested procedural advice from the Australian government concerning relinquishment of the Vic P60 permit. On April 16, 2010 the government returned its final Notice of Intent to Cancel that permit. We are awaiting the date of final cancellation.

Results of Operations

Total consulting, management, office, travel and professional expenses for the three and six month periods ended June 30, 2010 increased by approximately $53,000 (54%) and $222,000 (86%), respectively, when compared to the same periods during the prior year. This increase relates primarily to contract and travel fees incurred during 2010 in our search for joint venture partners.

The Australian dollar decreased from .92 to .86 US dollars and from .89 to .86 US dollars during the three and six month periods ended June 30, 2010, respectively. As a result, we recognized foreign exchange gains of $312,916 and $180,205 during the respective periods. Substantially all of our non-cash foreign exchange gain/losses relates to the measurement of US dollars required to settle deferred taxes payable to the Australian Government.

On August 15, 2009, we established a Non-Qualified Stock Option Plan. In connection with that plan, we recognized non-cash, stock-based compensation expense of $379,211 and $758,421 during the three and six month periods ended June 30, 2010, respectively.

We have recognized inception to date net losses of approximately $11,870,000. Those losses include the net impact of the discontinued operations of Endeavor Canada totaling $1,671,000 and a net impairment of oil and gas properties of approximately $5,152,000 related to the relinquishment of our offshore concessions. Residual losses relate to exploration stage operations.

Financial Condition, Liquidity and Capital Resources

The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. The US and other world economies are recovering from a recession which continues to inhibit investment liquidity. Though improved, fluctuating oil and gas prices provide additional uncertainty in capital markets. Our access to capital, as well as that of our partners and contractors, could be limited due to tightened credit markets and may inhibit the formation of exploration ventures. As a result, the development of our property interests may be delayed due to financial constraints.

Further, our oil and gas leases are highly sensitive to the market price of oil and the availability of capital required to fulfill our lease obligations in a timely manner. In the event capital remains unavailable for an extended period, the value of our oil and gas leases may be impaired.

Early estimates indicate the costs to perform the minimum required work over the life of our Cooper Basin licenses would range from $8.5 million to $10 million. Based upon technical recommendations, however, we intend to pursue the acquisition of a combination of 2-D and 3-D seismic data on our licenses. Our current exploration plan also calls for the drilling of more than the two wells required by the minimum work program. Early estimates indicate the costs to perform the work outlined in our current Cooper Basin exploration plan would range from $27 million to $30 million.

Our Cooper Basin exploration plan calls for the expenditure of approximately $10 million prior to August 31, 2011. We intend to joint venture our work program obligations with third parties which will pay all, or a significant portion, of the costs required to explore for oil and gas in the area covered by our permits.

On August 28, 2009 we retained Tristone to assist us in finding a joint venture partner to share all or part of the costs of exploring, and developing our Cooper Basin concessions. We have agreed to pay Tristone work fees of up to CAD$300,000, depending on the extent of services provided, and fees ranging between CAD$800,000 and CAD$1,000,000 if Tristone is successful in arranging a transaction acceptable to us. We are under no obligation to complete any transaction proposed as a result of this process.

During 2010, we substantially completed processing of more than 666 km (414 miles) of 2D seismic data. We expect to pay approximately $150,000 in connection with that effort.

11

In September 2008, we entered into an Administrative Services Agreement with our largest shareholder, Holloman Corporation. Beginning September 1, 2008, administrative services fees of $50,000 per month were payable to Holloman Corporation. These fees were paid quarterly in shares of our restricted common stock at the average closing price of the stock for the last ten trading-days of the applicable monthly billing period. In exchange for its fees, Holloman Corporation agreed to provide, among other things; executive consultation, management advice, engineering and geological services, office space, office support, communications, IT support, secretarial services, and the costs of North American travel expenses incurred in connection with the performance its services. The agreement under which these fees are incurred can be terminated by either party with 30-days notice.

As part of our cost cutting efforts, we amended our Administrative Service Agreement with Holloman Corporation to cancel fees payable under that agreement through September 30, 2010. As a result, no such fees were incurred during 2009 or the three and six month periods ended June 30, 2010.

Other than the obligations associated with our oil and gas concessions in Australia, we have no material future contractual obligations as of June 30, 2010.

Our operations have been financed from the sale of our securities, loans from unrelated third parties and advances from Holloman Corporation, our current and former officers, directors and their affiliates.

During the six months ended June 30, 2009, we repaid $840,000 in advances payable to related parties.

We believe our plan of operations may require up to $12,000,000 for exploration costs and administrative expenses over the twelve-month period ending August 31, 2011. We are attempting to raise investment capital and enter into joint ventures with third parties who will pay all, or a significant portion of the costs required to explore for oil and gas and otherwise fulfill the obligations required by our Australian licenses.

If we are unable to raise the financing we need, our business plan may fail and our stockholders could lose their investment. If we are unable to perform in accordance with the work programs set forth in our licenses, the Australian government could cancel our exploration rights. There can be no assurance that we will be successful in raising the capital we require, or that if capital is offered, it will be subject to terms we consider acceptable. Investors should be aware that even in the event we are able to raise the funds we require, there can be no assurance that we will succeed in our drilling or production plans and we may never be profitable.

As of August 10, 2010 we did not have any off balance sheet arrangements.

As of August 10, 2010 we did not have any proven oil or gas reserves and we did not have any revenues.

Critical Accounting Policies and Estimates

Measurement uncertainty

The process of preparing financial statements requires that we make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements; accordingly, actual results may differ from estimated amounts. The most significant estimates with regard to the financial statements included with this report relate to carrying values of oil and gas properties, determination of fair values of stock based transactions, and deferred income tax rates and timing of the reversal of income tax differences.

These estimates and assumptions are reviewed periodically and, as adjustments become necessary they are reported in earnings in the periods in which they become known.

12

Petroleum and natural gas properties

We utilize the full cost method to account for our investment in oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, capitalized interest costs relating to unproved properties, geological expenditures, tangible and intangible development costs, including direct internal costs are capitalized to the full cost pool. When we commence production from established proven oil and gas reserves, capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, will be depleted on the units-of-production method using estimates of proved reserves. Costs of unproved properties are not amortized until the proved reserves associated with the projects can be determined or until impairment occurs. If an assessment of such properties indicates that properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized.

The capitalized costs included in the full cost pool are subject to a "ceiling test", which limits such costs to the aggregate of the (i) estimated present value, using a ten percent discount rate, of the future net revenues from proved reserves, based on current economic and operating conditions, (ii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, (iii) the cost of properties not being amortized, less (iv) income tax effects related to differences between the book and tax basis of the cost of properties not being amortized and the cost or estimated fair value of unproved properties included in the costs being amortized. At June 30, 2010, all of our oil and gas interests were classified as unproven properties and were not being amortized.

Sales of proved and unproved 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 the statement of operations.

Foreign currency translation

Our functional and reporting currency, and that of our Australian subsidiary, is the United States dollar. The financial statements of our former Canadian subsidiary are translated to United States dollars using period-end rates of exchange for assets and liabilities, and average rates of exchange for the period for revenues and expenses. Translation gains (losses) are recorded in accumulated other comprehensive income as a component of stockholders’ equity. Foreign currency financial statements of our Australian subsidiary use period end rates for monetary assets and liabilities, historical rates for historical cost balances, and average rates for expenses. Transaction gains and losses are included in the determination of income. Foreign currency transactions are primarily undertaken in Canadian and Australian dollars. As of June 30, 2010, we have not entered into derivative instruments to offset the impact of foreign currency fluctuations.

Deferred income taxes

We follow the asset and liability method of accounting for future income taxes. Under this method, future income tax assets and liabilities are recorded based on temporary differences between the carrying amount of balance sheet items and their corresponding tax bases. In addition, the future benefits of income tax assets, including unused tax losses, are recognized, subject to a valuation allowance, to the extent that it is more likely than not that such future benefits will ultimately be realized. Future income tax assets and liabilities are measured using enacted tax rates and laws expected to apply when the tax liabilities or assets are to be either settled or realized.

Earnings per share

We present both basic and diluted earnings (loss) per share (EPS) on the face of the consolidated statements of operations. Basic EPS is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS gives effect to all dilutive potential common shares outstanding during the period including convertible debt, stock options, and warrants, using the treasury stock method. Diluted EPS excludes all dilutive potential shares if their effect is anti-dilutive. Diluted EPS figures are equal to those of basic EPS for each period since we have no dilutive stock options and warrants.

13

ITEM 4.

CONTROLS AND PROCEDURES

An evaluation was carried out under the supervision and with the participation of our management, including our Principal Financial Officer and Principal Executive Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-Q. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-Q, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of June 30, 2010, our disclosure controls and procedures were not effective to satisfy the objectives for which they are intended.

Change in Internal Control over Financial Reporting

Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.

There were no changes in our internal control over financial reporting identified in connection with the evaluation performed that occurred during the fiscal quarter covered by this report that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.

14

PART II -OTHER INFORMATION

ITEM 6.

EXHIBITS

Exhibit

15

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

16