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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

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 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

2500 CityWest Blvd., Suite 1300, Houston, Texas 77042

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes: o No: o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of May 14, 2010, was 27,150,278.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

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PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Operations

(unaudited)

*General and administrative expenses for the three month period ended March 31, 2010 and 2009 included non-cash stock-based compensation expense of $384,701 and $537,285, respectively. General and administrative expenses for the nine month period ended March 31, 2010 and 2009 included non-cash stock-based compensation expense of $1,201,137 and $1,645,535, respectively.

See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2010 and 2009 are as follows:

See accompanying notes to consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Preparation

Nature of Operations.  Evolution Petroleum Corporation (“EPM”), including its subsidiaries (the “Company”, “we”, “our” or “us”), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada.  We are engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas.  We acquire properties with known oil and natural gas resources and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

Interim Financial Statements.  The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included.  The interim financial information and notes hereto should be read in conjunction with the Company’s 2009 Annual Report on Form 10-K for the year ended June 30, 2009, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation.  Such reclassifications have no impact on previously reported income or stockholders’ equity.

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes, the amounts recoverable from the carry-back of income tax losses and the valuation of deferred tax assets, stock-based compensation, and commitments and contingencies.  We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Note 2 — Recent Accounting Pronouncements

New Accounting Standards.  The following discloses the existence and effect of accounting standards issued but not yet adopted by us with respect to accounting standards that may have an impact on the Company when adopted in the future.

Modernization of Oil and Gas Reporting.  On December 31, 2008, the SEC released new requirements for reporting oil and gas reserves (the “Modernization Requirements”).  The Modernization Requirements, when effective, provide for consideration of current technology in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, require reporting of oil and gas reserves using an average price based on the prior 12-month period rather than period-end prices, revise the disclosure requirements for oil and gas operations, and revise accounting for the limitation on capitalized costs for full cost companies.  The Modernization Requirements are effective for fiscal years ending on or after December 31, 2009.  A company may not apply the Modernization Requirements to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.  We have not yet evaluated the effects the Modernization Requirements will have on our financial statements.

The SEC staff issued Staff Accounting Bulletin (“SAB”) 113 (“SAB 113”), which revises portions of the guidance included in SAB Topic 12, Oil and Gas Producing Activities.  Specifically, SAB 113 revises the relevant interpretive guidance in SAB Topic 12 to conform it to the Modernization Requirements.

On January 6, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, an update of ASC Topic 932 Extractive Activities - Oil and Gas (“Topic 932”), which substantially aligns the reserve estimation, disclosure requirements, and definitions of Topic 932 with the disclosure requirements of the Modernization Requirements issued by the SEC.

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Note 3 — Property and Equipment

As of March 31, 2010 and June 30, 2009 our oil and natural gas properties and other property and equipment consisted of the following:

Unproved properties not subject to amortization include unevaluated acreage of $6.7 million and $7.5 million as of March 31, 2010 and June 30, 2009, respectively, consisting of properties in the Giddings Field in Central Texas, the Woodford Shale trend in Oklahoma, and the Lopez Field in South Texas (our “Neptune oil project”).  Unproved properties also include $2.0 million as of March 31, 2010 and June 30, 2009, of participating interests through royalty and overriding royalty interests aggregating 7.4% in the Delhi Holt Bryant Unit of the Delhi Field in Louisiana and a 25% after payout reversionary working interest in the Delhi Holt Bryant Unit along with a 25% working interest in certain other depths in the Delhi Field.  We incurred $1.1 million and $0.3 million as of March 31, 2010 and June 30, 2009, respectively, related to the drilling of three test wells and re-entry of four test wells on our acreage in Wagoner County in Oklahoma and $1.0 million as of March 31, 2010 on two wells on our acreage in South Texas.  Production testing of our wells in Oklahoma and South Texas is ongoing.  Evaluation of our unproved properties is expected to be completed within one to five years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

Note 4 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the nine months ended March 31, 2010:

Note 5 — Stockholders’ Equity

On September 8, 2009, the Board of Directors authorized and the Company issued 138,224 unrestricted and fully vested shares of common stock from the 2004 Stock Plan to certain employees for the payment of fiscal 2009 bonuses.  The value of the shares issued was $370,440, based on the fair market value on the date of issuance, or $2.68 per share.  The amount of bonus was accrued as of June 30, 2009 and recognized as a long-term liability. On September 8, 2009, when the shares were issued, the liability was reclassified to stockholders’ equity.

On September 8, 2009, the Board of Directors authorized and the Company issued 324,597 shares of restricted common stock from the 2004 Stock Plan to employees as a long-term incentive award.

On October 27, 2009, 119,795 shares of common stock were issued through a net cashless exercise of a placement warrant.  The placement warrant, which was issued to Cagan McAfee Capital Partners, LLC (“CMCP”), a related party (See Note 8), on May 26, 2004 in connection with a financing transaction, gave CMCP the right to purchase 165,000 shares, with an exercise price of $1.00 per share (See Note 9).

On November 10, 2009, 5,833 shares of common stock were issued through a net cashless exercise of a placement warrant.  The placement warrant, issued on November 30, 2004 in connection with a financing transaction, gave the holder the right to purchase 10,000 shares, with an exercise price of $1.50 per share (See Note 9).

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Note 5 — Stockholders’ Equity (Continued)

On December 9, 2009, a total of 42,317 shares of restricted common stock were issued to four outside directors as part of their board compensation for calendar year 2010.  All issuances of common stock were subject to vesting terms per individual stock agreements, which is generally one year for directors.

On February 6, 2010, a total of 38,182 shares of restricted common stock were forfeited by an employee.  The shares were cancelled and are available for a future grant in the 2004 Stock Plan.

On March 5, 2010, a total of 20,000 shares of restricted stock were issued to a new employee as long-term incentive compensation.  The shares are subject to a four year vesting term.

Note 6 — Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted and fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock.  No shares are available for grant under the 2003 Stock Plan and, as of March 31, 2010, 519,505 shares remain available for grant under the 2004 Stock Plan.

We have also granted common stock warrants, as authorized by the Board of Directors, to employees in lieu of cash bonuses or as incentive awards to reward previous service or provide incentives to individuals to acquire a proprietary interest in the Company’s success and to remain in the service of the Company (the “Incentive Warrants”).  These Incentive Warrants have similar characteristics of the Stock Options.  A total of 1,037,500 Incentive Warrants have been issued, with Board of Directors approval, outside of the EPM Stock Plans.  We have not issued Incentive Warrants since the listing of our shares on the NYSE Amex (formerly, the American Stock Exchange) in July 2006.

Stock Options and Incentive Warrants

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended March 31, 2010 and 2009 was $250,154 and $500,000, respectively.  Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the nine months ended March 31, 2010 and 2009 was $777,168 and $1,445,987, respectively.

There were no Stock Options granted during the nine months ended March 31, 2010.  During the nine months ended March 31, 2009, we granted Stock Options to purchase 591,090 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $4.27.  The exercise price was determined based on the market price of the Company’s common stock on the date of grant.  The Stock Options granted during the nine months ended March 31, 2009 vest quarterly, on a straight line basis, over a period of four years and have a contractual life of seven years.

The weighted average assumptions used to calculate the fair value of these Stock Options and the weighted average fair value of each option granted are as follows:

We estimated the fair value of Stock Options and Incentive Warrants issued to employees and directors at the date of grant using the Black-Scholes-Merton valuation model.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.  The expected term (estimated period of time outstanding) of Stock Options and Incentive Warrants is based on the “simplified” method of the estimated expected term for “plain vanilla” options allowed by the SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No. 110, and varied based on the vesting period and contractual term of the Stock Options or Incentive Warrants.   Expected volatility is based on the historical volatility of the Company’s closing common stock price and that of an evaluation of a peer group of similar companies trading activity.  We have not declared any cash dividends on the Company’s common stock.

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Note 6 — Stock-Based Incentive Plan (Continued)

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of March 31, 2010, and the changes during the period:

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($4.64) as of March 31, 2010) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were no Stock Options or Incentive Warrants that were exercised during the nine months ended March 31, 2010 and 2009.

A summary of the status of our unvested Stock Options and Incentive Warrants as of March 31, 2010 and the changes during the nine months ended March 31, 2010, is presented below:

During the nine months ended March 31, 2010 and 2009, there were 430,748 and 764,200 Stock Options and Incentive Warrants that vested with a total grant date fair value of $1,033,795 and $1,360,276, respectively.

The total unrecognized compensation cost at March 31, 2010, relating to non-vested Stock Options and Incentive Warrants was $1,282,686.  Such unrecognized expense is expected to be recognized over a weighted average period of 1.7 years.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended March 31, 2010 and 2009 was $134,547 and $37,285, respectively.  Stock-based compensation expense related to Restricted Stock grants for the nine months ended March 31, 2010 and 2009 was $423,969 and $199,548, respectively.

On September 8, 2009, the Board of Directors authorized and the Company issued 324,597 shares of restricted common stock from the 2004 Stock Plan to employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $869,917 related to the long-term incentive award will be recognized ratably over a four year vesting period.

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Note 6 — Stock-Based Incentive Plan (Continued)

On December 9, 2009, a total of 42,317 shares of restricted common stock were issued to four outside directors as part of their board compensation for calendar year 2010.  Total unrecognized stock-based compensation expense of $167,956 related to board compensation will be recognized ratably over a one year vesting period.  In the previous year, a total of 130,113 shares of restricted common stock, with a grant-date fair value of $167,965, were issued to the same outside directors as part of their board compensation for calendar year 2009, and which vested in December 2009.

On February 6, 2010, a total of 38,182 shares of restricted common stock, with a grant-date fair value of $187,965, were forfeited by an employee.  The shares were cancelled and are available for a future grant under the 2004 Stock Plan.

On March 5, 2010, a total of 20,000 shares of restricted stock, with a grant-date fair value of $90,000, were issued to a new employee as long-term incentive compensation.  The shares are subject to a four year vesting term.

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2010:

At March 31, 2010, unrecognized stock-based compensation expense related to Restricted Stock grants totaled $1,737,189.  Such unrecognized expense is expected to be recognized over a weighted average period of 3.2 years.

Note 7 — Income Taxes

We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

Since the FASB required recognition of unrecognized tax benefits and through March 31, 2010, there were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits.  We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2007 through June 30, 2009.

Our effective tax rate for any period may differ from the statutory federal rate, due primarily to stock-based compensation related to qualified incentive stock option awards (“ISO awards”), a permanent tax difference for financial reporting, as these types of awards, if certain conditions are met, are not deductible for federal tax purposes.

In January 2010, we received $2.1 million from the Internal Revenue Service as a result of the carry-back of our tax loss for the year ended June 30, 2009, for income taxes paid for our year ended June 30, 2007.  Significant intangible drilling costs were incurred during the 2009 fiscal year, of which, we elected to expense approximately $4.8 million for federal income tax purposes.  Under GAAP, and specifically the full-cost accounting method, intangible drilling costs are capitalized as part of oil and natural gas properties, and depleted using the unit-of-production method.  The deduction of intangible drilling costs created a significant difference in the income tax and book basis of our oil and natural gas properties, the most significant component of our deferred income tax liability as of March 31, 2010 and June 30, 2009.

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Note 8 — Related Party Transactions

Laird Q. Cagan, a member of our Board of Directors, is a Managing Director and co-owner of Cagan McAfee Capital Partners, LLC (“CMCP”).  CMCP has performed financial advisory services to us pursuant to a written agreement amended in December 2008.  Also pursuant to the Agreement, Mr. Cagan, as a registered representative of Colorado Financial Services Corporation and as a partner of CMCP, could serve as our placement agent in private equity financings, wherein CMCP could earn cash fees equal to 8% of gross equity proceeds, declining to 4% subject to the amount of equity raised through CMCP, and a fixed 4% warrant fee.  We have not paid placement fees to CMCP under this agreement since May 2006.

Eric A. McAfee, a major shareholder of the Company, is also a Managing Director of CMCP.

On October 27, 2009, we issued CMCP 119,795 shares of common stock through a net cashless exercise of a placement warrant.  The placement warrant, which was issued to CMCP on May 26, 2004 in connection with a financing transaction, gave CMCP the right to purchase 165,000 shares of common stock, with an exercise price of $1.00 per share (See Note 5).

Note 9 — Net loss Per Share

The following table sets forth the computation of basic and diluted loss per share:

* Potential dilutive common shares are excluded from the computation of net loss per common share because their effect is anti-dilutive.

Total outstanding potentially dilutive securities as of March 31, 2010 are as follows:

Total outstanding potentially dilutive securities as of March 31, 2009 are as follows:

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Note 10 — Commitments and Contingencies

We are subject to various claims and contingencies in the normal course of business.  In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdiction in which we operate.  We disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We establish reserves if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss.  Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of March 31, 2010 under this operating lease are as follows:

Rent expense for the three months ended March 31, 2010 and 2009 was 36,324 and 39,232, respectively.  Rent expense for the nine months ended March 31, 2010 and 2009 was 115,286 and 110,165, respectively.

Employment Contracts.  We have entered into employment agreements with the Company’s three senior executives.  The employment contracts provide for a severance package for termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination.   The total contingent obligation under the employment contracts as of March 31, 2010 is approximately $499,000.

Note 11 — Subsequent Events

Effective as of April 14, 2010, 4,913 shares of common stock were issued to a non-affiliate through a net cashless exercise of a placement warrant based on the closing sale price of the Company’s common stock on the day before exercise.  The placement warrant, issued on June 22, 2006 in connection with a financing transaction, gave the holder the right to purchase 8,000 shares, with an exercise price of $2.25 per share (See Note 9).

Effective as of April 16, 2010, 2,464 shares of common stock were issued to a non-affiliate through a net cashless exercise of a placement warrant based on the closing sale price of the Company’s common stock on the day before exercise.  The placement warrant, issued on June 22, 2006 in connection with a financing transaction, gave the holder the right to purchase 4,000 shares, with an exercise price of $2.25 per share (See Note 9).

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

The following is Management’s Discussion and Analysis (“MD&A”) of our financial position and operating results during the periods included in the accompanying unaudited consolidated condensed financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated condensed financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended June 30, 2009.

Forward-Looking Information

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2009 Annual Report on Form 10-K for the year ended June 30, 2009 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.  We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation.

General Overview

We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas. We originate project development concepts, capture such opportunities through the acquisition of known, underdeveloped oil and natural gas resources and exploit them through the application of capital and technology to increase production, ultimate recoveries, or both.

Our strategy is intended to generate scalable development opportunities at normally pressured depths, exhibiting relatively low completion risk, generally longer and more predictable production lives, less expenditures on infrastructure and lower operational risks.

Within this overall strategy, we pursue three specific initiatives:

I                    Enhanced oil recovery (“EOR”), using miscible and immiscible gas flooding;

II        Conventional redevelopment of bypassed primary resources within mature oil and natural gas fields utilizing modern technology and our expertise; and

III            Unconventional gas resource development, using modern stimulation and completion technologies.

Our most significant asset is our EOR project in the 13,636 acre Delhi Field, located in northeast Louisiana.  Our interests consist of 7.4% in overriding and mineral royalty interests, a 25% after pay-out reversionary working interest (20% revenue interest) in the Delhi Field Holt Bryant Unit, and a 25% working interest (20% revenue interest) in certain other depths in the Delhi Field, resulting from the Farmout we completed on June 12, 2006, with Denbury Onshore LLC, a subsidiary of Denbury Resources Inc. (the “Operator”) (the “Delhi Farmout”).  The Holt Bryant Unit is currently being redeveloped by the Operator, using CO2 enhanced oil recovery technology and a dedicated portion of the Operator’s proved CO2 reserves in the Jackson Dome, located approximately 100 miles east of Delhi.  Following several years of development by the Operator, CO2 injection had begun at the Delhi Field in November 2009, followed by initial oil production in March 2010.

Since our closing of the Delhi Farmout, we have focused on developing projects in our other initiatives through conventional redevelopment of oil and rich gas in the Giddings Field using horizontal drilling, development of gas resources in the shallow portion of the Woodford and Caney Shale Trend in Eastern Oklahoma, development of potential oil reserves in the mature Lopez Field within our Neptune oil project in South Texas and development of our proprietary artificial lift technology intended to extend the life of horizontal wells with oil or associated water production.

Our long-term strategy and primary focus continue to be on increasing share value through the identification and acquisition of resources and conversion of those resources into proved reserves through our expertise and technology.

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Highlights for our Third Quarter 2010

Projects

·                 First oil production flowed at our Delhi EOR project in March 2010, ahead of recent schedule.  As previously reported, we had expected first oil production would begin by mid-calendar 2010, following the initiation of CO2 injection last November. For March 2010, the operator reported 7,359 gross barrels of sales at Delhi, covering two weeks of active production from only the first three producer wells in the initial injection pattern. Denbury is continuing its multi-year roll out of the project by adding additional producer and injector wells and associated facilities in the field, thereby increasing our expected production through the 7.4% of royalty interests we hold throughout the EOR project’s life. The increasing field production is also gradually reducing the remaining portion of the deemed $200 million payout, based on Denbury’s receipt of field revenues less direct field operating expense, at which point we receive a 25% working interest and an incremental 20% revenue interest (increasing our revenue interest to 27.4%). We continue to bear no capital expenditures or operating costs until such payout occurs, after which we begin paying our 25% share of future costs.

·                 Commercialization of our artificial lift technology continues.  Our installed technology continues to operate in the Giddings Field and demonstrate its applicability, although the test well was shut-in extensively for compressor repairs during the quarter.  We are continuing discussions with a third party to apply our technology to their marginal, uneconomic or shut-in wells.

·                 Electric power became operational at our Neptune oil project, but first production was delayed due to water injection well repairs.  Drilling of our first two producer wells in the Lopez Field in South Texas has been completed, but first testing was delayed due to delays in obtaining access to electric power service.  Once remedied, production testing began, and was then further delayed due to injection rate issues in the well re-entered for use as a water injection well.  At the end of the quarter, operations necessary to increase injection capacity and allow the startup of production testing were in process.  As previously reported, we had expected test production to begin in FQ3, which we have now moved to FQ4.  We hold 1,710 net acres with the potential for up to 111 additional drilling locations, of which four locations have been assigned by our outside reservoir engineer as proved.

·                 Test production began in our shallow Oklahoma gas shale project.    In late February we began steady-state production from our vertical Woodford Shale test well in Wagoner County, Oklahoma.  As expected, production has steadily increased from an initial low rate as we have dewatered the localized area of the reservoir.  At the end of March, production stood at 40 mcf and 500+ barrels of water per day, and by the end of April, gas production had not only exceeded our targeted peak rate of 80mcfd with continued decline in water production, but the gas rate continues to steadily increase.  At this time, we are unable to predict the final peak gas rate in this well.  These results are encouraging and consistent with Antrim Shale production characteristics, wherein the dewatering process relieves the hydrostatic formation pressure to allow increasing gas rates, typically followed by a long slow decline curve.  While one test well result does not necessarily imply similar results in future wells to be drilled on our leases, we are encouraged in that our Wagoner County leases are bracketed by our test well on the west side of our lease block and a substantial number of producing Woodford Shale wells operated by others just outside the east side of our lease block.  As previously reported, in a separate test well we also performed a brief production test of the Caney Shale following a light frac of a vertical well in the same prospect area. The test confirmed a water free, low gas rate as a potential add-on to our Woodford production. Currently, production in this well has been shut-in, waiting on a second, much larger frac before further testing.

·                  Giddings Field production continues at a flatter decline rate, while we consider development options. We performed several workovers at Giddings during F3Q to help optimize future production.  With blended product prices somewhat improving, mostly driven by higher liquids prices, we began to solicit and consider proposals for accelerating development of our 21 proved undeveloped locations at Giddings, as further described in the “Looking forward” section below.

Operations

·                 Sales volumes decreased 33%, while product prices increased 65%, resulting in an 11% increase in revenues during our third quarter of fiscal 2010 compared to our third quarter of fiscal 2009.  The decline in our sales and production were mostly due to the initial steep decline rate in the Hilton Yegua #1 in the Giddings Field that was completed and placed on production during January 2009.  This well peaked during the quarter ended March 31, 2009 at 254 BOE per day, compared to average production of 27 BOE per day during the quarter ended March 31, 2010.  The decline may be a result of a possible obstruction in the horizontal section of the wellbore early-on in the life of the well.  Overall, natural gas accounted for 57% of our volumes sold during the current period compared to 44% for the same period in fiscal 2009 due to the better than expected results in the Pearson well that was completed in January 2009.  The average price we received was $44.98 per BOE during the three months ended March 31, 2010, as compared to $27.27 per BOE during the three months ended March 31, 2009.

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·      Production rates have flattened in general, with annualized decline rates slowing to under 10% since the quarter ended June 30, 2009.  Net production during the quarter averaged approximately 319 net BOE per day, compared to a quarterly rate of 340 net BOE per day for the quarter ended December 31, 2009, 344 net BOE per day for the quarter ended June 30, 2009 and 474 net BOE per day for the quarter ended March 31, 2009, respectively.  In particular, our best well, the Pearson #1, still produced at a gross rate of approximately 1.05 MMCFE per day for the month of April, 2010 after fifteen months of production.

·                 Our field breakeven point remains low.  During the three months ended March 31, 2010, lifting costs (lease operating expense and production taxes, on a combined per unit of sales basis) were $14.12 and our depletion rate was $17.23 per BOE, equaling a field income break-even point of $31.35 per BOE.  This compares to lifting costs of $12.37 and our depletion rate was $17.27, equaling a field income break-even point of $29.64 per BOE, during the quarter ended December 31, 2009. The increase in lifting costs during the quarter was due in material part to unusually high workover activity at Giddings.

Finances

·                 We ended our 3rd quarter of fiscal 2010 with $5.3 million of working capital, compared to $7.6 million at June 30, 2009.  The $2.3 million reduction in our working capital since June 30, 2009, was due to investments of $2.8 million in oil and natural gas properties, offset by positive cash flow generated from our oil and gas properties.

·                 Cash flows from operations provided for our general and administrative expenses and funded a portion of our capital expenditures.  Our decrease in working capital since the beginning of our 2010 fiscal year was due almost entirely to capital spending on our oil and gas projects.  Cash flows from operations were $2.2 million during the nine months ended March 31, 2010, which includes $2.1 million received in January from the Internal Revenue Service as a result of a carry-back of our tax loss for the year ended June 30, 2009 and net payments on working capital of $0.3 million.

·                 G&A expense was reduced 25% and 22% during the three and nine months ended March 31, 2010, respectively, as compared to the respective periods in the prior fiscal year.  In addition to reduced non-cash stock-based compensation expense, we have reduced our staff and legal costs during the year.

·                 We remained debt free. All of our expenditures were funded solely by working capital and we ended the quarter with no funded debt.

Looking forward

We continue to focus on:

Continued progress in our Delhi EOR project.

·              We expect continuing production increases at Delhi over the next few years.  Although we don’t control the operations of our Delhi EOR project, we expect Delhi production to steadily increase to a peak rate of about 10,000 gross barrels per day in the next 5 to 8 years as Denbury continues to expand the project.  Following a deemed payout, expected to occur in about 4 years, subject to oil prices and actual production levels being realized in line with our outside reserve report, we would own 27.4% of gross production, over one-fourth of which would bear no operating expense.

·              Establish proved reserves at Delhi.  Under current SEC rules, proved reserves cannot be assigned to our Delhi EOR property before the first EOR oil production response.  The SEC’s “Modernization” rules that become effective for us on June 30, 2010, state that reservoir engineers can consider relevant factors other than production in assigning proved reserves to EOR projects, including current technology, the results of field pilot tests and EOR projects in geologically comparable fields, all of which we believe are characteristics of the EOR project at Delhi.  Since an oil production response has occurred, we expect to be able to categorize a significant amount of proved reserves at Delhi under both sets of rules.

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Selective low cost testing and development of our portfolio properties.

·                 Upgrade our shallow multi-pay shale gas reserves.  We will continue our production testing in the Oklahoma shallow Woodford and Caney gas shales to demonstrate peak production rates, decline curves and estimated ultimate recovery in order to move this project into full scale development.  We also plan to re-enter a well in our mid-depth project in Haskell County, OK to begin testing the Woodford Shale reservoir between 4,000’ and 5,000’ depth.

·                 Continue to pursue commercial joint ventures utilizing our proprietary artificial lift technology.

·                 Establish production in our Neptune oil project.  We expect to begin first production in two producing wells in our 100% owned Neptune oil project in South Texas during our fourth fiscal quarter, with the goals of upgrading potential reserves and adding oil production.

·                 Conduct workovers in Giddings as justified to maintain net production to cover our overhead.

·                 Develop joint venture(s) to drill or monetize undeveloped locations at Giddings.  We are considering options to accelerate the drilling of our proved and unproved drilling locations, subject to natural gas, oil and NGL prices.

Continued conservative financial management.

·                 Emphasize long-term share value over near-term earnings.

·                 Retain financial strength, flexibility and liquidity to assure we obtain proper value for our core assets.

·                 Use internally generated funds and our working capital for continued development and testing, while considering joint ventures, project financing, asset redeployments and/or appropriate modest use of our common stock to fund growth through additional development of our core projects and new projects.

Liquidity and Capital Resources

For the current fiscal year, we expect to finance our budgeted oil and gas activities through our working capital and our cash flows from operating activities.

At March 31, 2010, our working capital was $5.3 million and we continued to be debt free.  This compares to working capital of $7.6 million at June 30, 2009.  The $2.3 million decrease in working capital since June 30, 2009, was due primarily to investments of $2.8 million in oil and natural gas properties (not including $0.1 million incurred related to recognition of asset retirement obligations).  Of the $2.8 million of incurred capital expenditures during the nine months ended March 31, 2010, $0.2 million was for leasehold acquisitions and $2.6 million was for development activities.  Development activities were in the Giddings Field in Texas, our Neptune oil project in South Texas, and our gas shale project in Eastern Oklahoma.

Cash Flows from Operating Activities

Cash flows provided by operating activities for the nine months ended March 31, 2010 were $2.2 million.  Cash flows provided by operations include cash receipts of $3.6 million from oil and natural gas sales, primarily from our properties in the Giddings Field, cash receipts of $2.1 million from the Internal Revenue Service due to our 2009 tax year net operating loss carry-back, and interest received of $0.1 million.  Total cash received of $5.8 million was partially offset by $3.3 million of cash payments for operating expenses, including lease operating expenses, production taxes, and salaries and wages, and payment of $0.3 million in state income taxes.

Cash flows provided by operating activities for the nine months ended March 31, 2009 were $6.2 million, which included cash receipts of $6.4 million from oil and natural gas production primarily from our properties in the Giddings Field, interest received of $0.1 million, cash receipts of $4.1 million from the Internal Revenue Service, primarily from our 2008 tax year net operating loss carry-back, offset by cash payments of $0.1 million for settling liabilities associated with our asset retirement obligations and $4.3 million of cash payments for operating activities, including lease operating expenses, production taxes, and salaries and wages.

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Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2010 and 2009, was $3.0 million and $9.9 million, respectively, which includes net payments on accounts payable of $0.2 million and $2.0 million, respectively, relating to prior period expenditures for oil and natural gas properties.

We purchased $1.4 million and $1.7 million in short-term certificates of deposit during the nine months ended March 31, 2010 and 2009, respectively.   During the nine months ended March 31, 2010, $2.1 million of certificates of deposit matured.

Cash Flows from Financing Activities

There were no significant cash flows from financing activities during the nine months ended March 31, 2010.  During the previous nine month period, on October 30, 2008, we repurchased 788,200 shares of common stock at an average price of $1.10 per share plus $0.02 in transaction costs from an unaffiliated accredited investor.

Capital Budget

We previously reported in our annual report for the fiscal year ended June 30, 2009, that we expected capital expenditures of approximately $3.0 million during fiscal year 2010.  As of March 31, 2010, we had incurred $2.8 million for capital expenditures related to our oil and gas activities. Due to our positive working capital, cash flows from producing properties and no debt, we believe that our current sources of liquidity are sufficient to fund our budget.

Results of Operations

Three months ended March 31, 2010 and 2009

The following table sets forth certain financial information with respect to our oil and natural gas operations:

(a)          Excludes depreciation of furniture and fixtures of $10,797 and $9,769, for the three months ended March 31, 2010 and 2009, respectively.

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Net loss.  For the three months ended March 31, 2010, we reported a net loss of $551,521 or $0.02 loss per share (which includes $384,701 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,291,381.  This compares to a net loss of $1,036,617, or $0.04 per share (which includes $537,285 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,164,464 for the three months ended March 31, 2009.  An increase in our revenues of $126,917 and a decrease in operating expenses of $532,145 were partially offset by a decrease of $184,718 in our income tax benefit.  Additional details of the components of net loss are explained in greater detail below.

Sales Volumes.  Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended March 31, 2010 decreased 33% to 28,710 BOE, compared to 42,698 BOE for the three months ended March 31, 2009.  Our sales volumes for the three months ended March 31, 2010 included 559 Bbls of oil from Delhi and 28,151 BOE from our properties in the Giddings Field in Texas.  Our sales volumes for the three months ended March 31, 2009 were primarily from our properties in the Giddings Field in Texas.  Sales volumes of natural gas decreased 12%, while sales volumes of crude oil and NGLs decreased 49% compared to the three months ended March 31, 2009.

During January of 2009, we completed and placed on production the Hilton Yegua #1.  This well produced at peak production during the three months ended March 31, 2009.

We recorded approximately $43,000 of revenue from first EOR oil production in our Delhi enhanced oil recovery project that began in the last two weeks of March 2010.

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues for the three months ended March 31, 2010 increased 11% from the three months ended March 31, 2009.  The increase was due to a 65% increase in the average price received per BOE of $27 for the three months ended March 31, 2009 to $45 per BOE for the three months ended March 31, 2010, partially offset by a 33% decrease in sales volumes.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the three months ended March 31, 2010 increased 42% compared to the three months ended March 31, 2009, primarily due to the additions of three producing wells and ad valorem taxes assessed in calendar year 2009.  Lease operating expense and production taxes per barrel of oil equivalent increased 111% from $6.69 per BOE during the three months ended March 31, 2009, to $14.12 per BOE during the three months ended March 31, 2010.  Lease operating expense per BOE for the three months ended March 31, 2009 was heavily influenced by the initial high rate of production from the Hilton Yegua #1 completed in January 2009.

General and Administrative Expenses (“G&A”).  G&A expenses decreased 25% to $1.2 million for the three months ended March 31, 2010, compared to $1.6 million for the three months ended March 31, 2009.  The reduction was due, primarily, to a decrease in non-cash stock-based compensation expense, which was $384,701 (32% of total G&A) and $537,285 (34% of total G&A) for the three months ended March 31, 2010 and 2009, respectively, and a reduction of legal fees of approximately $158,000 due to the settlement of the Delhi litigation in July 2009.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and, as a result, will likely continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A decreased by 33% to $505,445 for the three months ended March 31, 2010, compared to $759,836 for the three months ended March 31, 2009.  The decrease is due to a 33% reduction in net sales volumes.

Interest Income.  Interest income for the three months ended March 31, 2010 increased $10,752 to $18,776, compared to $8,024 for the three months ended March 31, 2009.  We received interest of $9,925 from the Internal Revenue Service in January 2010 related to the carry back of our 2009 tax loss.  The average daily balances of short term certificates of deposit remained consistent with the same period in the previous fiscal year.

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Nine months ended March 31, 2010 and 2009

The following table sets forth certain financial information with respect to our oil and natural gas operations: