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 December 31, 2007

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

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) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨                     Accelerated filer  ¨                     Non-accelerated filer  x

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 February 14, 2008, was 26,860,439.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

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PART I - FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets

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 December 31, 2007 and 2006 included non cash stock-based compensation expense of $441,564 and $371,604, respectively. General and administrative expenses for the six month period ended December 31, 2007 and 2006 included non cash stock-based compensation expense of $817,571and $861,477, respectively.

See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flow

(unaudited)

See accompanying notes to consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Organization and Basis of Preparation

Headquartered in Houston, Texas, Evolution Petroleum Corporation and its subsidiaries, formerly Natural Gas Systems, Inc. (the “Company”, “EPM”, “we” or “us”), is a petroleum company incorporated under the laws of the State of Nevada, engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas.  We acquire established oil and gas properties and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

Our common stock is traded on the American Stock Exchange (“AMEX”) under the ticker symbol EPM.  Prior to July 17, 2006, our common stock was quoted on the OTC Bulletin Board under the symbol NGSY.OB.  Prior to May 26, 2004, our common stock was quoted on the OTC Bulletin Board under the symbol RLYI.OB.  Concurrently with the listing of our shares on the AMEX during July, 2006, we changed our name from Natural Gas Systems, Inc. to Evolution Petroleum Corporation to avoid confusion with similar names traded on the AMEX and to better reflect our business model.

At December 31, 2007, we conducted operations through our 100% working interests in our Tullos Field Area and our non-operated interests in our Delhi Field, both located onshore in Louisiana, and our 100% working interests in our Giddings field in Central Texas.  Our Tullos Field Area consists of approximately 156 producing wells out of 260 well bores across 599 acres of high water cut primary reserve production.  Our non-operated interests in the 13,636 acre Delhi Field consist of a 7.4% overriding and mineral royalty interest in the Delhi Holt Bryant Unit, a 25% after payout reversionary working interest in the Delhi Holt Bryant Unit, and a 25% working interest in certain other depths in the Delhi Field.  Our Delhi Holt Bryant Unit is undergoing redevelopment using CO2 enhanced oil recovery technology.  Our Giddings Field Area included proved undeveloped reserves some of which we have begun developing.

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) with the instructions to Form 10-Q for interim financial information.  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. All inter-company transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with the Company’s 2007 Annual Report on Form 10-KSB for the year ended June 30, 2007, as filed with the Securities and Exchange Commission. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

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.

Accounting for the Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”) No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), which permits all entities to choose, at specified election dates, to measure eligible items at fair value. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, and thereby mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007.  We are currently evaluating the impact that this Statement will have on our financial statements.

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Note 2 – Recent Accounting Pronouncements (Continued)

Accounting for Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The provisions of SFAS No. 157 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied except for, among other items, a financial instrument that was measured at fair value at initial recognition under Statement 133 using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157.  In February 2008, the FASB deferred the effective date of SFAS No. 157 by one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis and amended SFAS No. 157 to exclude SFAS No. 13, Accounting for Leases, and it related interpretive accounting pronouncements that address leasing transactions. We are currently evaluating the impact that this Statement will have on our financial statements.

Note 3 – Property and Equipment

Note 4 – Asset Retirement Obligations

Following is a reconciliation of the beginning and ending asset retirement obligation for the six month period ended December 31, 2007:

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Note 5 – Stock-Based Incentive Plan

Stockholders of record, as of October 15, 2007, voted at the 2007 Annual Meeting of Stockholders on December 4, 2007 to approve amendments to the 2004 Stock Plan to increase the number of shares of common stock we may authorize to issue from 4,000,000 shares to 5,500,000 shares and to make certain clarifying changes and amendments as part of the approval of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan.

We granted stock option awards to purchase common stock and 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” and together, the “EPM Stock Plans”).  A total of 600,000 shares were reserved for issuance under the 2003 Stock Plan, of which, there are no remaining shares available for grant.  A total of 5,500,000 shares are reserved for issuance under the 2004 Stock Plan and, as of December 31, 2007, 1,415,859 shares remained available for grant under the 2004 Stock Plan.

We have also granted common stock warrants, as authorized by the Board of Directors, to employees as bonus or  incentive awards to reward previous service or provide incentives to individuals to acquire a proprietary interest in the Company and to remain in the service of the Company (the “Incentive Warrants”).  These Incentive Warrants have similar characteristics of stock option awards.  They have been issued, with Board of Directors approval, outside of the 2004 Stock Plan.

Incentive Stock Options and Warrants

For the three month period ended December 31, 2007 and 2006, total stock based compensation expense recognized for common stock options and Incentive Warrants was $403,109 and $301,091, respectively.  Stock-based compensation expense related to the six month period ended December 31, 2007 and 2006 was $704,206 and $684,616, respectively.

During the six month period ended December 31, 2007, we granted options to purchase 1,335,000 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $2.43.  During the same period in 2006, we granted options to purchase 150,000 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $2.71.  The exercise price was determined based on the market price of the Company’s common stock at the date of grant.  The stock options granted during the six months ended December 31, 2007 vest over a weighted average period of 4.0 years and have a contractual life of ten years.  The weighted average assumptions used to calculate the fair value of these options and the weighted average fair value of these options are as follows:

We estimated the fair value of stock options and Incentive Warrants issued to employees and directors under SFAS No. 123R at the date of grant using a 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 option grants and Incentive Warrants is based on the “simplified” method of estimated expected term for “plain vanilla” options allowed by the SEC Staff Accounting Bulletin No. 107 and 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 issued any cash dividends on the Company’s common stock.

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Note 5 – Stock-Based Incentive Plan (Continued)

The following summary presents information regarding outstanding options and Incentive Warrants as of December 31, 2007, and the changes during the six months then ended:

(1) Based upon the difference between the market price of our common stock on the last trading date of the quarter and the option or Incentive Warrant exercise price of in-the-money options and Incentive Warrants.

A summary of the status of our unvested stock options and Incentive Warrants as of December 31, 2007, and the changes during the six months ended December 31, 2007, is presented below:

The total unrecognized compensation cost at December 31, 2007, relating to non-vested share-based compensation arrangements granted under the EPM Stock Plans and previously issued Incentive Warrants, was $4,006,561.  Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 3.0 years.

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Note 5 – Stock-Based Incentive Plan (Continued)

Restricted Stock

For the six months ended December 31, 2007, we granted a total of 25,899 shares of restricted common stock to three outside directors.  All issuances of common stock are subject to vesting terms per individual stock agreements.

During the three months ended December 31, 2007 and 2006, we recognized compensation expense of $38,455 and $70,513, respectively, related to restricted stock grants.  During the six months ended December 31, 2007 and 2006, we recognized compensation expense of $113,365 and $176,861, respectively, related to restricted stock grants.

The following table sets forth the restricted stock transactions for the six months ended December 31, 2007:

At December 31, 2007, unrecognized stock compensation expense related to restricted stock grants totaled approximately $107,973.  Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 0.9 years.

Note 6 – Commodity Hedging and Price Risk Management Activities

As of February 28, 2007, all of the Company’s commodity hedging and price risk management activities had expired and were not renewed.

Note 7 – Income Taxes

Uncertain Tax Positions

We did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing Interpretation No. 48 Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109 (“FIN48”).  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on the results of operations or the financial position of the Company.

We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.   With limited exceptions, the Company is no longer subject to U.S. Federal, state and local income tax examinations by tax authorities for years before fiscal year ended June 30, 2004.  There is currently an Internal Revenue Service (“IRS”) field examination in process for the fiscal year ended June 30, 2006. The examination is in the beginning stages and no projections as to the outcome can be made at this time.

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Note 7 – Income Taxes  (Continued)

The Company’s continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter.  We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2008.

We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes (“SFAS 109”). SFAS No. 109 requires us to recognize income tax benefits for loss carry forwards which have not previously been recorded. The tax benefits recognized must be reduced by a valuation allowance when it is more likely than not that the deferred tax asset will not be realized.

In determining the carrying value of a deferred tax asset, SFAS 109 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable.  We have placed a valuation allowance on certain deferred tax assets primarily inclusive of net operating losses (“NOL’s”) that are limited by Internal Revenue Code Section 382.   The Company had taxable income in 2006 and thus paid both federal and state income taxes.  A benefit is being recognized with the intention of carrying back the current year tax loss to 2006.  Sufficient income is available in 2006 to fully utilize the losses created in the current year.  Therefore, management believes no valuation allowance is necessary on the income tax benefit arising from the taxable loss in the current year.

The income tax benefit rate of 29% varies from the U.S. statutory rate primarily due to state income taxes partially offset by disallowed compensation costs related to incentive stock options.

Note 8 – Related Party Transactions

Laird Q. Cagan, Chairman of our Board, is a Managing Director and co-owner of Cagan McAfee Capital Partners, LLC (“CMCP”). CMCP performs financial advisory services to us pursuant to a written agreement amended in November 2005, providing for a retainer of $5,000 per month. In addition, Mr. Cagan, as a registered representative of Chadbourn Securities Inc. (“Chadbourn”) and a partner of CMCP, has served as the Company’s placement agent in private equity financings.  Under the current agreement, CMCP may earn cash fees equal to 8% of gross equity proceeds, declining to 4% subject to the amount of equity raised, and a fixed 4% warrant fee.  Mr. Cagan receives no additional compensation for serving as a director or as the Chairman of our Board.

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

During the three and six months ended December 31, 2007 and 2006 respectively, we expensed and paid CMCP $15,000 and $30,000, respectively, in quarterly retainers.  There were no other earned fees by CMCP.

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Note 9 – Net Loss per Share

Basic and diluted loss per share are computed by dividing net loss available to common shareholders by the weighted average number of common shares outstanding during the period.  For purposes of computing diluted loss per share, potential common shares have been excluded from the computation of weighted average common shares outstanding, because their effect is antidilutive.

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

Note 10 – Commitments and Contingencies

Environmental clean-up.  On August 3, 2007, we were advised of an oil spill in the Tullos Field near one of our leases. At the request of field agents of the Louisiana Department of Environmental Quality and the Environmental Protection Agency (“EPA”), we agreed to commence a clean-up operation that was completed by the end of August 2007. A detailed analysis of the oil in the spill compared to the Company’s produced oil was conducted by an EPA approved laboratory.  We believe that the oil in the spill did not originate from our operations, and this is supported by the formal findings of the laboratory.  We also believe that most of the approximately $700,000 of estimated costs to be incurred in the cleanup, before adjustment following audit, will be covered by insurance or reimbursement from the relevant government oil spill funds.  We received insurance proceeds of $484,197 in October 2007.  Furthermore, we have recorded an insurance receivable of $224,887 for costs incurred through December 31, 2007.  Clean up costs that aren’t covered by insurance are expensed as incurred.

Litigation.  In November 2005, a multi-plaintiff lawsuit was filed in the Fifth Judicial District Court, Richland Parish, Louisiana, against 18 defendants including NGS Sub Corp. and Arkla Petroleum LLC, the Company’s wholly owned subsidiaries (the “Subsidiaries”), as working interest owners/operators of various oil and gas leases in the Delhi Field. Plaintiffs claim that the defendants’ oil and gas exploration, development and production activities on their properties have caused soil and ground water contamination as a result of the release of hydrocarbons and drilling fluids. Plaintiffs seek damages for testing, clean-up and remediation of the properties as well as diminution in their value and mental anguish to the individual plaintiffs, unjust enrichment and punitive damages for alleged concealment of ongoing activities.

Certain exceptions filed by the defendants are still under consideration by the court.  Discovery has begun and the allegations of plaintiffs’ suit are so vague that the specifics of their claims cannot be determined yet with certainty.  Accordingly, the court has ordered the plaintiffs to file their claims with specificity.  Trial is set before a jury in Richland Parish for the first two weeks of September 2008.

Management intends to contest plaintiffs’ claims vigorously.  The plaintiffs have not produced any evidence of specific damage to their lands by defendants’ oil and gas operations.  While the Delhi Field has been in production for over fifty years, we believe that no contamination of significance occurred during the Subsidiaries’ period of ownership of the Delhi operating interests and Arkla Petroleum LLC as operator of said interests, beginning with our acquisitions of each in 2003 and ending with the our disposition of the Delhi operating interests in 2006.  We believe that our liability exposure results largely through any potential contractual indemnity of prior working interest owners.  Until such time as the specifics of plaintiffs’ claims are identified through the discovery process, and particularly any evidence of actual contamination of soil or groundwater, the amount of any judgment that might be rendered cannot be determined with accuracy.

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Note 10 – Commitments and Contingencies (Continued)

During the quarter ended June 2006, the Governor of the State of Louisiana signed into law new legislation addressing complaints similar to and including those filed against us.  Although the intention of the legislation was designed to limit plaintiff complaints and remedies by possibly deferring first to administrative experts within the Louisiana State Departments of Environmental Quality and Natural Resources, it is unclear at this time the impact of such legislation.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of December 31, 2007 under this operating lease are as follows:

Rent expense for the three months ended December 31, 2007 and 2006 was $35,466 and $10,730, respectively.  Rent expense for the six months ended December 31, 2007 and 2006 was $70,933 and $21,461, 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, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination.   The total obligation under the employment contracts as of December 31, 2007 is approximately $450,000.

Internal Revenue Service Examination.  We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.   With limited exceptions, the Company is no longer subject to U.S. Federal, state and local income tax examinations by tax authorities for years before fiscal year ending June 30, 2004.  There is currently an IRS examination in process for the fiscal year ended June 30, 2006. The examination is in the beginning stages and no projections as to the outcome can be made at this time.

Note 11 – Subsequent Events

On February 12, 2008, we entered into a consulting agreement with the Liviakis Financial Communications, which expires December 31, 2008, Inc. to provide investor relations services for the Company. In exchange for these services, the Company issued 50,000 shares of common stock, which is subject to monthly vesting, over the term of the agreement.

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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 gas, operating risks and other risk factors as described in our 2007 Annual Report on Form 10-KSB for the year ended June 30, 2007 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.

Critical Accounting Policies

Our 2007 Annual Report on Form 10-KSB describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments.

This Quarterly Report on Form 10-Q should be read in conjunction with the discussion contained in our 2007 Annual Report on Form 10-KSB regarding these critical accounting policies.

Executive Overview

General

Evolution Petroleum Corporation, formerly Natural Gas Systems, Inc., is a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas. We acquire established oil and gas properties and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

We are focused on an overall strategy of acquiring controlling working interests in oil and gas resources within established fields and redeveloping those fields through the application of capital and technology to convert a portion of the oil and gas resources into profitable producing reserves. 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:

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Our Initiative I EOR project at the 13,636 acre Delhi Field, located in northeast Louisiana, is currently our most strategic asset.  These non-operated interests consist of 7.4% in overriding and mineral royalty interests in the Delhi Field Holt Bryant Unit, a 25% after pay-out reversionary working interest in the Delhi Field Holt Bryant Unit, and a 25% working interest in certain other depths in the Delhi Field.  The Holt Bryant Unit is being redeveloped by the operator, Denbury Resources, using CO2 enhanced oil recovery technology, with CO2 injection expected by the operator in calendar 2008, followed by projected increases in oil production beginning in calendar 2009.  Since we are not the operator of the Delhi Field, we have no control of the timing or the success of field operations.  Since our closing of the Delhi CO2 Farmout, we have been focused on bringing Initiative II Bypassed Resource projects, Initiative III Unconventional Gas Resource projects and new Initiative I EOR projects to the forefront.  Conceptually, our plan going forward can be illustrated as follows:

As indicated by the above chart, we are funding our Bypassed Resource projects with our cash resources. We expect that net cash flows from these projects, our current cash resources and cash flows from Delhi CO2 project will be used to fund our Unconventional Gas Initiative and new projects spanning all of our initiatives.

First and Second Fiscal Quarter2008 Highlights

Our progress during the six months ended December 31, 2007 includes:

·                  Initial drilling operations in our Bypassed Resource projects, which began in December 2007;

·                  Development of our operational infrastructure and vendor network to support a continuous drilling program;

·                  Additional leasehold acquisitions of proved undeveloped reserves within our Bypassed Resource projects; and

·                  Additional acquisitions of unproved leasehold acreage within our Bypassed Resource and Unconventional Gas Development projects.

At December 31, 2007, we conducted operations through our 100% working interests in our Tullos Field Area and our non-operated interests in our Delhi Field, both located on shore in Louisiana, and our 100% working interests in our Giddings field in Central Texas. As of January 31, 2008, we have acquired approximately 13,000 gross and net acres within our Unconventional Gas Resource Initiative and 11,500 gross and net acres within our Bypassed Resource Initiative.

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Liquidity and Capital Resources

At December 31, 2007, our working capital, predominately cash and cash equivalents, was approximately $21.1 million, and we continued to be debt free.  This compares to working capital of approximately $27.3 million at June 30, 2007.  Of the $6.2 million decrease in working capital, $5.9 million was used for capital expenditures on oil and gas leasehold and development costs.

For the six months ended December 31, 2007, approximately $1.3 million was used in operations primarily through changes in working capital.  This compares to approximately $4.3 million used in operations for the six months ended in 2006, which includes $3.7 million used to extinguish income taxes payable.

Cash flows used in investing activities totaled approximately $4.9 million during the six months ended December 31, 2007 This compared to approximately $34.5 million provided by investing activities for the comparable six months of 2006.  During the six months ended December 31, 2006, $34.7 million was received by us from a qualified intermediary account into our operating account and approximately $0.2 million of cash was used for investments to acquire and develop oil and gas property interests.  During the six months ended December 31, 2007 approximately $4.9 million of cash was used for investments to acquire and develop oil and gas property interests, which does not include approximately $1.0 million in oil and gas expenditures remaining unpaid and carried in accounts payable as of December 31, 2007.

Cash flows from financing activities during the six months ended December 31, 2007, included cash proceeds received with issuance of restricted stock grants to three independent directors.  During the same period in 2006, we incurred approximately $15,592 of costs related to filing registration statements for previous equity raising matters.

We expect our capital expenditures will increase substantially during fiscal year 2008, due to continued leasing and the execution of a development drilling program within our Bypassed Resource Initiative, and continued leasing in our Unconventional Gas Initiative. Based on our current plans, we expect capital expenditures to exceed $15 million during fiscal 2008, with $8.5 million dedicated to development drilling and the balance to leasehold acquisitions.  We believe our working capital is sufficient to fund this drilling program.

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Results of Operations

Three months ended December 31, 2007 compared to three months ended December 31, 2006

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

(a)          Includes the cash settlement of hedging contracts in the prior year

(b)         Excludes non-recurring oil spill expenses in the current period of $14,532

Net Loss. For the three months ended December 31, 2007, we reported a net loss of  $770,857, or $0.03 loss per share (which, included approximately $0.6 million of non-cash charges related to stock based compensation and depreciation, depletion, and amortization), on total oil and gas revenues of $652,649, as compared to a net loss of $421,657, or $0.02 loss per share (which, included approximately $0.4 million of non-cash charges related to stock based compensation and depreciation, depletion, and amortization), on total oil and gas revenues of $426,459 for the three months ended December 31, 2006.  The increase to our net loss is primarily attributable to increases in general and administrative expenses of $507,164, primarily related to increased staff costs necessary to initiate our ten well drilling program and higher administrative costs, a decrease in interest income earned of $236,578, offset by an income tax benefit of $282,399 in the quarter ended December 31, 2007 as compared to no income tax benefit in the 2006 quarter.  Additional details of the components of net loss are explained in greater detail below.

Sales Volumes  Oil and gas sales volumes, net to our interest, for the three months ended December 31, 2007 increased 31% to 7,918 barrels of oil equivalent, compared to 6,080 BOE for the three months ended December 31, 2006.  The increase in oil and gas sales volumes is due primarily to first production of oil and natural gas in Texas as compared to the three month period ended December 31, 2006 and the sale of excess oil inventory in the Tullos Field Area not previously saleable. The initial oil and gas production in Texas occurred during re-entry operations of wells in preparation for drilling.

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Production.  Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Net working interest oil and gas production for the three months ended December 31, 2007 increased 7% to 6,987 Bbls, compared to 6,542 Bbls for the three months ended December 31, 2006.  The increase is primarily due to oil and natural gas production from our first well in Texas, offset by lower production in Tullos due to the lack of field services during the quarter.

Oil and Gas Revenues.  Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest.  Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts.  Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed.

Oil and gas revenues increased 53% for the three months ended December 31, 2007, compared to the same period in 2006, as a result of a 18% increase in the price of a barrel of oil equivalent (“BOE”), from $70 per BOE to $82 per BOE, and a 31% increase in sales volumes as described above.  The average sales price increase includes the effect of current quarter sales being 85% oil compared to 100% in the prior quarter.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses for the three months ended December 31, 2007 increased approximately 12% from the comparable 2006 period. The overall increase in lease operating expenses in 2007 is primarily attributable to higher field expenses in our Tullos Field.  On a BOE basis, lease operating expenses decreased by 13% over the comparable 2006 quarter, primarily due to an increase in sales volumes.

General and Administrative Expenses (G&A).  G&A expenses increased 53% to approximately $1.5 million for the three months ended December 31, 2007, compared to approximately $1 million for the three months ended December 31, 2006.  Higher overall compensation expenses for estimated accrued bonuses (whereas we did not accrue for bonuses in the prior comparable period) and new hires accounted for the majority of the increase, in addition to increases to franchise taxes owed for the State of Texas.  New hires are associated with building up our infrastructure to execute the planned drilling program. Non-cash stock compensation expense was $441,564 and $371,604 for the three months ended December 31, 2007 and 2006, respectively.

Depreciation, Depletion & Amortization Expense (DD&A).  DD&A expense increased $77,765 to $123,115 for the three months ended December 31, 2007 from $46,350 for the same period in 2006.  The increase is primarily due to a higher depletion rate ($13 vs. $8) per barrel.  The increase in depletion is due to the higher cost of Proved Undeveloped reserves at our Giddings field added to our lower cost Proved Developed Producing reserves from our Tullos Field Area.

Interest Income.  Interest income for the three months ended December 31, 2007 decreased $236,578 to $266,740, compared to $503,318 for the three months ended December 31, 2006.  The decrease in interest income is primarily due to lower available cash balances averaging approximately $23.4 million during most of the current quarter, as compared to cash balances averaging approximately $40 million in the comparable prior year quarter.  The lower cash balance is due to cash used to relieve income taxes payable arising from the $50 million we received from the Delhi Farmout and for additions to our oil and gas properties.

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Six months ended December 31, 2007 compared to six months ended December 31, 2006

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

(c)          Includes the cash settlement of hedging contracts in the prior year

(d)         Excludes non-recurring oil spill expenses in the current period of $38,123

Net Loss. For the six months ended December 31, 2007, we reported a net loss of $1,412,238, or $0.05 loss per share (which, included approximately $1.1 million of non-cash charges related to stock based compensation and depreciation, depletion, and amortization), on total oil and gas revenues of $1,154,922, as compared to a net loss of $881,693, or $0.03 loss per share (which, included approximately $1.0 million of non-cash charges related to stock based compensation and depreciation, depletion, and amortization), on total oil and gas revenues of $895,469 for the six months ended December 31, 2006.  The increase to our net loss is primarily attributable to increases to General and Administrative expenses of $796,290 as described below and a decrease in interest income earned of $426,292, offset by an income tax benefit of $568,986 in the six months ended December 31, 2007 as compared to no income tax benefit in the six months ended December 31, 2006.  Additional details of the components of net loss are explained in greater detail below.

Sales Volumes.  Oil and gas sales volumes, net to our interest, for the six months ended December 31, 2007 increased 9% to 14,952 BOE, compared to 13,775 BOE for the six months ended December 31, 2006.  The increase in oil and gas sales volumes is due primarily to first production oil and natural gas in Texas as compared to the three month period ended December 31, 2006 and the sale of excess oil inventory in the Tullos Field Area not previously saleable.

Production.  Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Net working interest oil and gas production for the six months ended December 31, 2007 decreased slightly to 14,132 BOE, compared to 14,144 BOE for the six months ended December 31, 2006.  This was primarily due to a decrease in oil production in our Tullos Field Area, offset by production from our Texas field. The initial oil and gas production in Texas occurred during re-entry operations of wells in preparation for drilling.

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Oil and Gas Revenues.  Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest.  Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts.  Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed.

Oil and gas revenues increased 29% for the six months ended December 31, 2007, compared to the same period in 2006, as a result of a 19% increase in the price of a barrel of oil equivalent (“BOE”), from $65 per BOE to $77 per BOE, and a 9% increase in sales volumes as described above.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses for the six months ended December 31, 2007 increased approximately 5% from the comparable 2006 period. The overall increase in lease operating expenses in 2007 is primarily attributable to higher field expenses in our Tullos Field.  On a BOE basis, lease operating expenses decreased by 9% over the comparable 2006 period.

General and Administrative Expenses (G&A).  G&A expenses increased 40% to approximately $2.8 million for the six months ended December 31, 2007, compared to approximately $2 million for the six months ended December 31, 2006.  Higher overall compensation expenses for estimated accrued bonuses (whereas we did not accrue for bonuses in the prior comparable period) and new hires accounted for the majority of the increase, in addition to increases in Franchise taxes owed to the State of Texas.  New hires are associated with building up our infrastructure to execute the planned drilling program. Non-cash stock compensation expense was $817,571 and $861,477 for the six months ended December 31, 2007 and 2006, respectively.

Depreciation, Depletion & Amortization Expense (DD&A).  DD&A expense increased $125,338 to $233,559 for the six months ended December 31, 2007 from $108,221 for the same period in 2006.  The increase is primarily due to a higher DD&A rate ($13 vs. $8) per barrel.  The increase in depletion is due to the higher cost of PUDs at our Giddings field that we added to our lower cost PDP’s from our Tullos Field Area.

Interest Income.  Interest income for the six months ended December 31, 2007 decreased $426,292 to $607,821, compared to $1,034,113 for the six months ended December 31, 2006.  The decrease in interest income is primarily due to lower available cash balances averaging approximately $24.6 million during the six months ended December 31, 2007, as compared to cash balances averaging approximately $42.3 million in the comparable prior year quarter.  The lower cash balance is due to cash used to relieve income taxes payable arising from the $50 million we received from the Delhi Farmout and for additions to our oil and gas properties.

Off Balance Sheet Arrangements

As of February 28, 2007, all of the Company’s commodity hedging and price risk management activities had expired and were not renewed.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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 gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and gas that we can economically produce. We may periodically use derivative instruments to hedge our commodity price risk. We may hedge a portion of our projected oil and gas production through a variety of financial and physical arrangements intended to support oil and 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 gas sales when the associated production occurs. We do not hold or issue derivative instruments for 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 of the end of the quarter covered by this report. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that 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.

There has been no change in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

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

On February 12, 2008, we entered into a consulting agreement with the Liviakis Financial Communications, which expires December 31, 2008, Inc. to provide investor relations services for the Company. In exchange for these services, the Company issued 50,000 shares of common stock, which is subject to monthly vesting, over the term of the agreement.  The Company relied on an exemption from registration under Section 21(2) of the Securities Act of 1933, as amended.  Liviakis Financial Communications is an accredited investor as defined in Regulation D, Rule 501(a).

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

The following matters were submitted to a vote of security holders during Evolution Petroleum’s Annual Meeting of Stockholders held on December 4, 2007:

1.               Election of Directors – The following nominees were elected to serve as Directors of Evolution Petroleum Corporation until the 2007 Annual Meeting of Stockholders: