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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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 November 13, 2009, was 27,118,766.

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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 months ended September 30, 2009 and 2008 included non-cash stock-based compensation expense of $391,636 and $523,725, 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 three months ended September 30, 2009 and 2008 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”) and 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 expected to be 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.

In September 2009, the Financial Accounting Standards Board (“FASB”) issued an exposure draft to align the reserve calculation and disclosure requirements of generally accepted accounting principles with the Modernization Requirements. As proposed, the exposure draft would be effective for reporting periods ending on or after December 31, 2009.

The SEC staff issued Staff Accounting Bulletin 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.

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Note 3 — Property and Equipment

As of September 30, 2009 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 $7.5 million as of September 30, 2009 and June 30, 2009, 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 include $2.0 million as of September 30, 2009 and June 30, 2009, of participating interests through royalty and overriding royalty interests aggregating 7.4% of the Delhi Holt Bryant Unit in the Delhi Field in Louisiana.  We incurred $0.7 million and $0.3 million as of September 30, 2009 and June 30, 2009, respectively, related to the drilling of three test wells and re-entry of four test wells, all vertical tests with light acid hydraulic fracturing, on our acreage in Wagoner County in Oklahoma.  Subject to industry conditions, evaluation of these 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 three months ended September 30, 2009:

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.  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

We have granted option awards to purchase common stock (the “Stock Options”) and restricted common stock awards (“Restricted 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.  There are no shares available for grant under the 2003 Stock Plan and, as of September 30, 2009, 543,600 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 American Stock Exchange) in July 2006.

On September 8, 2009, the Board of Directors authorized the issuance of 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 in lieu of cash.  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 August 19, 2008, the Board of Directors authorized the issuance of 46,795 unrestricted and fully vested shares of common stock from the 2004 Stock Plan to certain employees who elected to receive these shares in lieu of a portion of their fiscal 2008 cash bonus.  The value of the shares issued was $168,462, based on the fair market value on the date of issuance, or $3.60 per share.

Stock Options and Incentive Warrants

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended September 30, 2009 and 2008 was $265,252 and $445,993, respectively.

There were no Stock Options granted during the three months ended September 30, 2009.  During the three months ended September 30, 2008, 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 three months ended September 30, 2008 vest quarterly, on a straight line basis, over a period of four years.  The Stock Options granted during the three months ended September 30, 2008 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.

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of September 30, 2009, and the changes during the period:

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Note 6 — Stock-Based Incentive Plan (Continued)

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($2.97 as of September 30, 2009) 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 three months ended September 30, 2009 and 2008.

A summary of the status of our unvested Stock Options and Incentive Warrants as of September 30, 2009 and the changes during the three months ended September 30, 2009, is presented below:

During the three months ended September 30, 2009 and 2008, there were 144,833 and 229,062 Stock Options and Incentive Warrants that vested with a total grant date fair value of $260,699 and $389,405, respectively.

The total unrecognized compensation cost at September 30, 2009, relating to non-vested Stock Options and Incentive Warrants was $1,794,601.  Such unrecognized expense is expected to be recognized over a weighted average period of 2.1 years.

Restricted Stock

During the three months ended September 30, 2009, we issued 324,597 shares of Restricted Stock to certain employees as long-term incentive compensation.  There were no grants of Restricted Stock for the three months ended September 30, 2008.

Stock-based compensation expense related to Restricted Stock grants for the three months ended September 30, 2009 and 2008 was $126,384 and $77,732, respectively.

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Note 6 — Stock-Based Incentive Plan (Continued)

The following table sets forth the Restricted Stock transactions for the three months ended September 30, 2009:

At September 30, 2009, unrecognized stock compensation expense related to Restricted Stock grants totaled $1,964,783.  Such unrecognized expense will be recognized over a weighted average period of 3.8 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.

There were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits since the FASB required recognition of unrecognized tax benefits and through September 30, 2009.  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 the three months ended September 30, 2008 of 67%, significantly higher than the statutory federal rate, was due to stock-based compensation related to qualified incentive stock option awards (“ISO awards”), a permanent tax difference for financial reporting.  We recorded an expense of $396,394 for the three months ended September 30, 2008, related to ISO awards.  For the three months ended September 30, 2009, stock based compensation expense was primarily related to awards that are non-qualified for federal income tax purposes.

We expect to recover approximately $2.1 million in federal income taxes paid during the tax year ended June 30, 2007, as a result of the carry-back of our 2009 income tax loss.  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 September 30, 2009 and June 30, 2009.

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 November 2005 (the “Agreement”), providing for a retainer of $5,000 per month.  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.  During the term of the Agreement, Mr. Cagan received no compensation for serving as a director or as the Chairman of our Board of Directors.   Effective December 31, 2008, the Agreement was modified to remove the monthly retainer and Mr. Cagan was re-elected as a director of our Board with remuneration consistent with other outside directors of our Board.  During the three months ended September 30, 2008, we expensed and paid CMCP $15,000 through monthly retainers of $5,000.  There were no other transactions with CMCP.

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

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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) earnings per common shares if their effect is anti-dilutive. Potential dilutive common shares always will result in an anti-dilutive per-share amount when an entity has a loss from continuing operations and as such no potential dilutive common shares were included in the computation of diluted EPS for the three months ended September 30, 2009.

Total outstanding potentially dilutive securities as of September 30, 2009 are as follows:

Total outstanding potentially dilutive securities as of September 30, 2008 are as follows:

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.  As of September 30, 2009, and subsequently through the date these financial statements were issued, no claim or unasserted claim existed that required an accrual or disclosure.

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Note 10 — Commitments and Contingencies (Continued)

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of September 30, 2009 under this operating lease are as follows:

Rent expense for the three months ended September 30, 2009 and 2008 was $39,730 and $35,466, 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 September 30, 2009 is approximately $499,000.

Note 11 — Subsequent Events

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 CMCP 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.

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.

Subsequent events have been evaluated through November 13, 2009, the date these financial statements were issued.

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

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.

Executive Overview

General

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 acquire 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:

Our most significant asset is within our EOR Initiative in the 13,636 acre Delhi Field, located in northeast Louisiana.  Our non-operated interests consist of 7.4% in overriding and mineral royalty interests and a 25% after pay-out reversionary working interest in the Delhi Field Holt Bryant Unit, along with a 25% working 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.  During an Analyst Day presentation on November 12, 2009, the Operator announced that CO2 injection began at the Delhi Field earlier that day, with initial oil production response expected by mid-year calendar 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 and development of potential oil reserves in the mature Lopez Field within our Neptune project in South Texas.

We are funding our ongoing development from our working capital resources and from net cash flows from our properties in the Giddings Field.  Our expected future cash flows from the Delhi Project also will be used to fund full development of our projects and other new projects.  We also may utilize project financing and selected asset monetization in the future.

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 First Quarter 2010

Projects

·                 CO2 injection began at Delhi on November 12, 2009.  On November 12, 2009, the operator of the Delhi Field announced at their Analyst Day presentation that CO2 injection had begun earlier that day, and that they expected first oil production to begin around mid-calendar 2010.

·                 We successfully field tested our proprietary lift technology at Giddings.  As previously reported, the first well we re-entered and drilled horizontally in Giddings, the Donella #1, was also our poorest producer in the program due to previous depletion of the zone by an offset well.  After one year of production, the well became incapable of further commercial production on conventional rod pump.  During June 2009, we re-entered the well to install and test our proprietary artificial lift technology.  Commercial production was successfully re-established and steadily improved over its first two months of production.   The well is still on production.

·                 We drilled and completed our first test well at Neptune.  Testing of the productive rate is pending the completion of water disposal facilities. We also increased our net acreage holdings by 14% to 1,710 net acres on favorable terms, potentially adding 10-13 additional drilling locations.

·                 Update on proof of concept drilling in our shallow Oklahoma Gas Shale Project.   As previously reported, we initiated the drilling of three test wells and re-entry of three wells, all vertical tests with light acid hydraulic fracturing on our acreage in Wagoner County in Oklahoma.  The tests demonstrated a satisfactory initial rate of gas production from the Woodford Shale.  We also demonstrated that the Caney Shale is productive, thereby providing an additional zone that could be potentially co-produced with the Woodford.

Operations

·                 Sales volumes increased 3%, but product prices declined 61% during our first quarter of fiscal 2010 compared to our first quarter of fiscal 2009.  Essentially 100% of our production for the three months ended September 30, 2009 and 2008 was attributable to our properties in the Giddings Field.  Declines in crude oil and NGL production was more than offset by an increase in natural gas production, while revenues were driven down in the current period by substantial declines in both crude oil and natural gas prices.  During the three months ended September 30, 2009, the average price we received was $33.43 per BOE, as compared to $85.51 during the three months ended September 30, 2008.

·                 Our production declines have flattened, exiting our 1st quarter of fiscal 2010 at a combined rate of approximately 382 net BOE per day.  This compares to a sequential rate of 348 net BOE per day and comparable prior fiscal year quarterly rate of 371 net BOE per day for the three months ended June 30, 2009 and September 30, 2008, respectively.  All of our wells appear to have completed their initial period of steep production declines and exhibit shallower declines. In particular, our best well, the Pearson, has stabilized at a productive gross rate of 1.3 MMCFE per day after eight months of production.

·                 We lowered our field income break-even point by 9% over our 1st quarter of fiscal 2009 and 5% over our 4th quarter of fiscal 2009.  During the three months ended September 30, 2009, lifting costs (lease operating expense and production taxes, on a combined per unit of sales basis) were $10.95 and our depletion rate was $17.17 per BOE, equaling a field income break-even point of $28.12 per BOE.  This compares to lifting costs of $12.38 and a depletion rate of $18.63 per BOE, equaling a field income break-even point of $31.01 per BOE we experienced during the three months ended September 30, 2008 and to lifting costs of $12.59 and a depletion rate of $17.15 per BOE, equaling a field income break-even point of $29.74 per BOE we experienced during the three months ended June 30, 2009.

Finances

·                 We ended our 1st quarter of fiscal 2010 with $6.6 million of working capital, compared to $7.6 million at June 30, 2009.  At September 30, 2009, working capital included $5.1 million of cash and cash equivalents and short-term certificates of deposit, and $2.1 million of recoverable income taxes arising from current year tax losses being carried back to a prior tax year.  We incurred $1.1 million (not including $0.1 million related to amounts capitalized due to asset retirement obligations) in capital expenditures for oil and natural gas leasehold and development costs.

·                 Cash flows from operations provided for our general and administrative expenses and funded a portion of our capital expenditures.  Therefore, use of our working capital was entirely dedicated to our oil and gas projects.  Cash flows from operations were $324,250 during the three months ended September 30, 2009.

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·                 We protected our short-term investments during difficult credit market conditions.  We avoided higher risk credit instruments over the last year, relying instead upon lower yielding short-term U.S. Treasury money market funds and short-term certificates of deposit fully insured by the FDIC.

·                 Non-cash stock-based compensation expense of $0.4 million comprised over 30% of total general and administrative expenses during the three months ended September 30, 2009.  Non-cash stock-based compensation expense remains an important part of our total compensation program to help motivate and retain high performing employees and consultants, in addition to conserving our cash resources.

·                 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 into 2010

We continue to focus on:

Selective low cost testing and development of our portfolio properties.

·                 Upgrade our shallow multi-pay shale gas reserves.  We are continuing our test program in the Oklahoma shallow Woodford and Caney gas shales.  We have immediate plans to apply larger hydraulic fracturing using proppant in two wells, to separately test the Woodford and Caney reservoirs, to determine peak initial production rates and decline profiles.  We expect the results will allow us to design the appropriate development program and necessary facilities and gathering system. Later in the fiscal year, market conditions permitting, we plan to re-enter a well in our mid-depth project in Haskell County, OK to begin testing the Woodford and Caney Shale reservoirs between 4,000’ and 5,000’ depth.

·                 Pursue commercial joint ventures utilizing our proprietary artificial lift technology.  Based on tests results in our Donella #1, we believe this technology could re-establish production in many wells throughout the Giddings Field, and potentially other fields developed with horizontal wells.  We are installing this technology on a second well we own in the Giddings Field.  We have also initiated discussions with other producers, with the expectation of contributing our technology and expertise in exchange for an interest in the new production we might re-establish via our technology.

·                 Establish production in our Neptune oil project.  We expect to begin first production in our 100% owned Neptune oil project in South Texas with the drilling and completion of a second well that will allow low cost water disposal, and we plan to drill a second oil producer during the year.  This work will potentially upgrade additional proved reserves while adding oil production.

·                 Conduct workovers in Giddings to generate net production to cover our overhead.  We are performing workovers on certain wells to partially offset normal production declines and continue to generate sufficient cash flows to offset corporate cash overhead.

·                 Solicit joint venture(s) to drill Giddings PUD locations.  We are considering various options to accelerate the drilling of our proved and unproved undeveloped drilling locations, subject to stable natural gas, oil and NGL prices.

Continued progress in our Delhi EOR project.

·                 CO2 injection at Delhi began on November 12, 2009.

·                 First oil production at Delhi is expected by the Operator during mid-calendar 2010.

·                 Establish proved reserves at Delhi.  Under current SEC rules, proved reserves cannot be assigned to our Delhi EOR property until first EOR production response, projected by the Operator to occur by mid-year calendar 2010. Alternatively, the SEC’s “Modernization” rules that are scheduled to become effective on January 1, 2010, state that reservoir engineers can consider other relevant factors 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.

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Continued conservative financial management.

·                 Emphasize long-term share value over near-term earnings, particularly during periods of low natural gas prices.

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

·                 Primarily use internally generated funds and our working capital for fiscal 2010 goals, while considering joint ventures, project financing or non-core asset monetization to fund growth through development of our core projects and new projects.

Liquidity and Capital Resources

At September 30, 2009, our working capital was $6.6 million and we continued to be debt free.  This compares to working capital of $7.6 million at June 30, 2009.  The decrease in working capital of $1.0 million since June 30, 2009 was due primarily to investments of $1.1 million in oil and natural gas properties (not including $0.1 million incurred related to recognition of asset retirement obligations).

Cash flows provided by operating activities for the three months ended September 30, 2009 were $0.3 million.  Cash flows provided by operations include cash receipts of $1.2 million from oil and natural gas sales primarily from our properties in the Giddings Field.  Sources of cash were offset by $0.9 million of cash payments for operating activities, including lease operating expenses, production taxes, salaries and other general administrative expenses.  In comparison, cash flows provided by operating activities for the three months ended September 30, 2008 was approximately $2.2 million, which included cash receipts of approximately $3.9 million from oil and natural gas production primarily from our properties in the Giddings Field, net cash receipts of approximately $0.4 million from interest income and income tax refunds, offset by approximately $2.1 million of cash payments for operating activities, including lease operating expenses, production taxes, salaries and other general and administrative expenses.

Cash flows used in investing activities totaled $1.2 million during the three months ended September 30, 2009, which include the purchase of short-term certificates of deposit of $0.1 million.  Our remaining investing activities of $1.1 million were primarily for development of our properties in the Giddings Field, in our Neptune oil project in South Texas, and test drilling in our Woodford Shale projects in Oklahoma.  In comparison, cash flows used in investing activities totaled approximately $4.0 million during the three months ended September 30, 2008, consisting of approximately $3.9 million used for investments to acquire and develop oil and natural gas property interests, including net payments on June 30, 2008 accounts payable of approximately $1.5 million relating to prior period expenditures for oil and natural gas properties

There were no cash flows from financing activities during the three months ended September 30, 2009 and 2008.

We incurred $1.1 million of capital expenditures for oil and natural gas leasehold and development costs during three months ended September 30, 2009, plus an additional $0.1 million related to recognition of asset retirement obligations.  Of the $1.1 million of incurred capital expenditures during the three months ended September 30, 2009, $0.1 million was for leasehold acquisitions and $1.0 million was for development activities.  Development activities were in the Giddings Field, in our Neptune oil project in South Texas, and test drilling in our Woodford Shale acreage.

Due to our positive working capital, cash flows from producing properties and no debt, we believe we have the ability to fund or further adjust our capital expenditure budget to capture select opportunities that may arise for the benefit of our shareholders, without the need of additional financing.  Therefore, we believe that our current sources of liquidity are sufficient to fund our ongoing cash requirements.

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Results of Operations

Three months ended September 30, 2009 and 2008

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

(a)          Excludes depreciation of office equipment, furniture and fixtures, and other of $16,627 and $9,824, for the three months ended September 30, 2009 and 2008, respectively.

Net loss.  For the three months ended September 30, 2009, we reported a net loss of $704,825, or $0.03 loss per share (which includes $391,636 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,170,027.  This compares to a net income of $148,437, or $0.01 per share (which includes $523,725 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $2,914,986 for the three months ended September 30, 2008.  A decrease in our revenues of $1,744,959 and a decrease in interest income of $58,422 was offset by decreases in operating costs of $268,935 (primarily related to a decrease in stock-based compensation and depreciation, depletion, and amortization), and a recognition of an income tax benefit of $378,348 (compared to a provision for income taxes of $302,836 for the three months ended September 30, 2008).  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 September 30, 2009 increased 3% to 35,004 BOE, compared to 34,089 BOE for the three months September 30, 2008.  Our sales volumes for the three months ended September 30, 2009 and 2008 was primarily from our properties in the Giddings Field in Texas.  Production of natural gas increased 82%, while production of crude oil and NGLs decreased 31% compared to the three months ended September 30, 2008.

Oil, NGLs and Natural Gas Revenues.  Crude oil, NGLs and natural gas revenues for the three months ended September 30, 2009 decreased 60% from the three months ended September 30, 2008.  This was due to a 61% decline in the average price received per BOE, from $86 per BOE for the three months ended September 30, 2008 to $33 per BOE for the three months ended September 30, 2009.

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Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the three months ended September 30, 2009 decreased 9% compared to the three months ended September 30, 2008, despite the addition of three producing wells.  The decrease is primarily attributable to a decrease in production taxes.

General and Administrative Expenses (“G&A”).  G&A expenses decreased 14% to $1.3 million for the three months ended September 30, 2009, compared to $1.5 million for the three months ended September 30, 2008.  The reduction was primarily due to a decrease in non-cash stock-based compensation expense, which was $391,636 (31% of total G&A) and $523,725 (36% of total G&A) for the three months ended September 30, 2009 and 2008, respectively, and a fifteen percent reduction in staff.  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 4% to $617,757 for the three months ended September 30, 2009, compared to $644,882 for the three months ended September 30, 2008.  The decrease is primarily due to a lower depletion rate ($17.17 vs. $18.63) per BOE, as a result of the reduction in projected capital expenditures associated with our proved undeveloped locations in our properties in the Giddings Field, partially offset by the 3% increase in net sales volumes.

Interest Income.  Interest income for the three months ended September 30, 2009 decreased $58,422 to $15,224, compared to $73,646 for the three months ended September 30, 2008.  The decrease in interest income is due to much lower interest rates available on lower short-term investment balances averaging $5.5 million during the three months ended September 30, 2009, as compared to short-term investment balances averaging $10.4 million during the three months ended September 30, 2008.  The lower balances were primarily due to investments in our oil and natural gas properties during the prior twelve months.

Inflation.  Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements.  With the general rise in the price of oil and natural gas products over two of the last three fiscal years, increased prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services, have also increased, thereby escalating our lease operating expenses and our capital expenditures.  Most recently, we have seen a substantial decline in both petroleum product prices and drilling and oilfield services costs.  However, product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties.  General worldwide economic conditions have deteriorated due to credit conditions impacted by the sub-prime mortgage turmoil and other factors.  Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which has resulted in reduced demand for crude oil and natural gas.  If demand decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward.

Seasonality.  Our business is generally not seasonal, except for certain rare instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products.  Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, generally based on higher demand for natural gas in the summer and winter and higher demand for downstream oil products during the summer driving season.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the first quarter ending September 30, 2009.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended September 30, 2009, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2009 except as noted below.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended June 30, 2009.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.  Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. Lower prices may also reduce the amount of oil and natural gas that we can economically produce.  Although our current production base may not be sufficient enough to effectively allow hedging, we may periodically use derivative instruments to hedge our commodity price risk. We may hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and natural gas sales when the associated production occurs. We presently do not hold or issue derivative instruments for hedging or speculative purposes.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and the Company’s Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2009 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

During the quarter ended September 30, 2009 there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

See risk factors set forth in the Company’s Annual Report on Form 10-K for the year ended June 30, 2009.

ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

A.           Exhibits

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SIGNATURES

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

EVOLUTION PETROLEUM CORPORATION

(Registrant)

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