UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		41-1781991
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

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.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o		Smaller reporting company 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 May 12, 2011, was 27,554,566.

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PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Unaudited Consolidated Balance Sheets

	March 31,			June 30,
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	2,953,481		$	3,138,259
Certificates of deposit	250,000			1,350,000
Restricted cash from joint interest partner	225,847			—
Receivables
Oil and natural gas sales	1,062,741			536,366
Joint interest partner	363,390			—
Income taxes	25,200			25,200
Other	862			147,059
Income taxes recoverable	—			716,973
Prepaid expenses and other current assets	267,274			315,494
Total current assets	5,148,795			6,229,351

Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties — full-cost method of accounting, of which $4,987,112 and $7,851,068 at March 31, 2011 and June 30, 2010, respectively, were excluded from amortization.	33,151,080			30,803,061
Other property and equipment	76,443			101,998
Total property and equipment	33,227,523			30,905,059

Other assets	54,117			60,665

Total assets	$	38,430,435		$	37,195,075

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	511,926		$	678,609
Joint interest advances	214,068			—
Accrued compensation	501,323			75,692
Royalties payable	654,175			221,062
Income taxes payable	139,620			202,334
Other current liabilities	72,725			110,002
Total current liabilities	2,093,837			1,287,699

Long term liabilities
Deferred income taxes	2,886,870			2,949,880
Asset retirement obligations	827,987			811,635
Stock-based compensation	—			587,033
Deferred rent	84,468			81,635

Total liabilities	5,893,162			5,717,882

Commitments and contingencies (Note 9)

Stockholders’ equity
Preferred stock, par value $0.001; 5,000,000 shares authorized; no shares issued or outstanding.	—			—
Common stock; par value $0.001; 100,000,000 shares authorized; issued 28,342,766 shares;outstanding 27,554,566 shares and 27,061,376 shares as of March 31, 2011 and June 30, 2010, respectively.	28,342			27,849
Additional paid-in capital	20,368,673			18,532,643
Retained earnings	13,022,280			13,798,723
	33,419,295			32,359,215
Treasury stock, at cost, 788,200 shares as of March 31, 2011 and June 30, 2010.	(882,022		)	(882,022		)

Total stockholders’ equity	32,537,273			31,477,193

Total liabilities and stockholders’ equity	$	38,430,435		$	37,195,075

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Unaudited Consolidated Statements of Operations

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Revenues
Crude oil	$	1,607,521		$	469,418		$	3,034,333		$	1,428,915
Natural gas liquids	228,050			282,400			669,463			847,923
Natural gas	181,504			539,563			661,807			1,385,872
Total revenues	2,017,075			1,291,381			4,365,603			3,662,710

Operating Costs
Lease operating expense	284,577			399,833			950,382			1,134,607
Production taxes	26,308			5,432			54,084			40,258
Depreciation, depletion and amortization	132,516			505,445			358,963			1,673,344
Accretion of asset retirement obligations	16,233			15,562			43,314			45,100
General and administrative *	1,359,161			1,194,872			3,976,115			3,701,584
Total operating costs	1,818,795			2,121,144			5,382,858			6,594,893

Income (loss) from operations	198,280			(829,763		)	(1,017,255		)	(2,932,183		)

Other income
Interest income	1,562			18,776			13,034			47,785

Net income (loss) before income tax benefit	199,842			(810,987		)	(1,004,221		)	(2,884,398		)

Income tax (provision) benefit	(29,416		)	259,466			227,778			926,112

Net income (loss)	$	170,426		$	(551,521	)	$	(776,443	)	$	(1,958,286	)

Earnings (loss) per common share
Basic	$	0.01		$	(0.02	)	$	(0.03	)	$	(0.07	)
Diluted	$	0.01		$	(0.02	)	$	(0.03	)	$	(0.07	)

Weighted average number of common shares
Basic	27,521,957			27,144,174			27,379,023			26,959,713
Diluted	30,833,505			27,144,174			27,379,023			26,959,713

*General and administrative expenses for the three month period ended March 31, 2011 and 2010 included non-cash stock-based compensation expense of $392,533 and $384,701, respectively. General and administrative expenses for the nine month period ended March 31, 2011 and 2010 included non-cash stock-based compensation expense of $1,143,413 and $1,201,137, respectively.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Nine Months Ended March 31,
	2011			2010
Cash flows from operating activities
Net loss	$	(776,443	)	$	(1,958,286	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	358,963			1,673,344
Stock-based compensation	1,143,413			1,201,137
Accretion of asset retirement obligations	43,314			45,100
Payments on asset retirement obligations	(1,847		)	—
Deferred income taxes	(261,965		)	(867,207		)
Accrued compensation	—			315,000
Deferred rent	2,833			2,833
Other	32,080			4,678
Changes in operating assets and liabilities
Receivables from oil and natural gas sales	(526,375		)	(84,866		)
Receivables from income taxes and other	1,125,374			2,137,875
Due from joint interest partner	(230,227		)	—
Prepaid expenses and other current assets	48,220			(38,614		)
Accounts payable and accrued expenses	273,286			(121,058		)
Royalties payable	433,113			54,539
Income taxes payable	(125,963		)	(157,736		)
Net cash provided by operating activities	1,537,776			2,206,739

Cash flows from investing activities
Proceeds from asset sale	231,326			—
Development of oil and natural gas properties	(2,320,102		)	(2,767,758		)
Acquisitions of oil and natural gas properties	(814,323		)	(185,141		)
Maturities of certificates of deposit	1,100,000			2,059,147
Purchases of certificates of deposit	—			(1,350,000		)
Other assets	(25,532		)	(8,851		)
Net cash used in investing activities	(1,828,631		)	(2,252,603		)

Cash flows from financing activities
Proceeds from the issuance of restricted stock	28			42
Proceeds from the exercise of stock options	106,049			—
Net cash provided by financing activities	106,077			42

Net decrease in cash and cash equivalents	(184,778		)	(45,822		)

Cash and cash equivalents, beginning of period	3,138,259			3,891,764

Cash and cash equivalents, end of period	$	2,953,481		$	3,845,942

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2011 and 2010 are as follows:

	Nine Months Ended
	March 31,
	2011			2010
Income taxes paid	$	152,000		$	251,800

Income tax refunds and carry backs received	$	979,177		$	2,095,126

Non-cash transactions
Decrease in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties:	$	(196,557	)	$	(187,681	)
Increase in accounts payable related to joint venture activities:	$	144,942		$	—
Oil and natural gas properties incurred through recognition of asset retirement obligations:	$	(25,115	)	$	70,871

See accompanying notes to consolidated condensed financial statements.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED 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 condensed 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 2010 Annual Report on Form 10-K for the fiscal year ended June 30, 2010, 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: NGS Sub Corp and its wholly owned subsidiary, Tertiaire Resources Company, NGS Technologies, Inc., and Evolution Operating Co., Inc. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous period may include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported loss 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 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 — Property and Equipment

As of March 31, 2011 and June 30, 2010 our oil and natural gas properties and other property and equipment consisted of the following:

	March 31, 2011			June 30, 2010
Oil and natural gas properties
Property costs subject to amortization	$	33,321,024		$	27,775,641
Less: Accumulated depreciation, depletion, and amortization	(5,157,056		)	(4,823,648		)
Unproved properties not subject to amortization	4,987,112			7,851,068
Oil and natural gas properties, net	$	33,151,080		$	30,803,061

Other property and equipment
Furniture, fixtures and office equipment, at cost	260,476			260,476
Less: Accumulated depreciation	(184,033		)	(158,478		)
Other property and equipment, net	$	76,443		$	101,998

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 2 — Property and Equipment (Continued)

Unproved properties not subject to amortization includes unevaluated acreage of $2.8 and $6.0 million as of March 31, 2011 and June 30, 2010, respectively, consisting of properties in the Giddings Field in Central Texas, the Woodford Shale trend in Oklahoma, and, as of June 30, 2010, the Lopez Field in South Texas (our “Neptune Oil Project”). Unproved properties also includes $0.7 million as of March 31, 2011 and June 30, 2010, relating to our interests in the Delhi Field in Louisiana. Unproved properties also includes $1.4 and $1.2 million as of March 31, 2011 and June 30, 2010, respectively, related to the drilling of test wells and re-entry wells on our acreage in Wagoner County in Oklahoma. Production testing of our wells in Oklahoma is ongoing. Development of our unproved properties is expected to be completed within one to five years. Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

Note 3 — Joint Interest Drilling Arrangement

In July 2010, we entered into a drilling arrangement with an industry partner to drill up to five horizontal development wells in the Giddings Field in central Texas. Our industry partner has funded $7,103,360 through March 31, 2011, their portion of the approval for expenditure (“AFE’) for the first three wells. As of March 31, 2011, $214,068 of their funding has yet to be incurred with respect to those wells. We have billed our industry partner $363,390 for operating expense recovery and costs incurred for their share of supplemental AFEs. Amounts pertaining to our industry partner’s share of the joint interest drilling arrangement included in our balance sheet as of March 31, 2011, are as follows:

Restricted cash from joint interest partner	$	225,847
Amounts due from joint interest partner	363,390
Accounts payable	144,942
Joint interest advances	214,068

Note 4 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the nine months ended March 31, 2011:

Asset retirement obligations — beginning of period	$	811,635
Accretion	43,314
Payments on asset retirement obligations	(1,847		)
Revision of estimate	(25,115		)
Asset retirement obligations — end of period	$	827,987

Note 5 — Stockholders’ Equity

On July 2, 2010, an employee of the Company exercised 6,875 stock options granted in 2007 at an exercise price of $2.33 per share. See Note 6.

On July 2, 2010, a total of 4,215 shares of restricted common stock were forfeited by an employee. Total unrecognized stock-based compensation expense related to the shares was $11,621. The shares were cancelled and are available for a future grant in the 2004 Stock Plan. See Note 6.

On August 9, 2010, a total of 30,233 shares of restricted stock were issued to a new employee as long-term incentive compensation. The value of the shares issued was $156,000, based on the fair market value on the date of issuance. The shares are subject to a four year vesting term. See Note 6.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 5 — Stockholders’ Equity (Continued)

On September 10, 2010, the Board of Directors authorized and the Company issued 106,927 shares of common stock from the 2004 Stock Plan to certain employees for the payment of fiscal 2010 bonuses. The value of the shares issued were $587,033, based on the fair market value on the date of issuance, or $5.49 per share. The amount of bonus was accrued as of June 30, 2010, and recognized as a long term liability. On September 10, 2010, the date of the share issuance, the liability was reclassified to additional paid-in capital.

On September 10, 2010, the Board of Directors authorized and the Company issued 240,478 shares of restricted common stock from the 2004 Stock Plan to certain employees as a long-term incentive award. Total unrecognized stock-based compensation expense of $1,320,224 related to the long-term incentive award will be recognized ratably over a four year period as the restricted common stock vests. See Note 6.

On October 1, 2010, a total of 4,845 shares of restricted stock were issued to a new employee as long-term incentive compensation. The value of the shares issued was $29,118, based on the fair market value on the date of issuance. The shares are subject to a four year vesting term.

On December 9, 2010, a total of 28,047 shares of restricted common stock was issued to four outside directors as part of their board compensation for calendar year 2011. The value of the shares issued was $168,000, based on the fair market value on the date of issuance. All issuances of common stock were subject to vesting terms per individual stock agreements, which is generally one year for directors.

On December 21, 2010, an employee of the Company exercised 30,000 stock options granted in 2003 at an exercise price of $0.001 per share. See Note 6.

On February 28, 2011, a former consultant of the Company exercised 50,000 stock options granted in 2005 at an exercise price of $1.80 per share. See Note 6.

Note 6 — Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”). Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan. The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock. No shares are available for grant under the 2003 Stock Plan and 180,170 shares remain available for grant under the 2004 Stock Plan as of March 31, 2011.

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

Stock Options and Incentive Warrants

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended March 31, 2011 and 2010 was $172,728 and $250,154, respectively. Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the nine months ended March 31, 2011 and 2010 was $542,299 and $777,168, respectively.

There were no Stock Options granted during the nine months ended March 31, 2011 and 2010.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 6 — Stock-Based Incentive Plan (Continued)

We estimated the fair value of Stock Options and Incentive Warrants issued to employees and directors 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 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 March 31, 2011, and the changes during the fiscal year:

	Number of Stock Options and Incentive Warrants		Weighted Average Exercise Price		Aggregate Intrinsic Value (1)		Weighted Average Remaining Contractual Term (in years)

Stock Options and Incentive Warrants outstanding at July 1, 2010	5,482,820		$	1.83

Granted	—		—
Exercised	(86,875	)	$	1.22
Cancelled or forfeited	(3,125	)	$	2.33
Expired	—		—

Stock Options and Incentive Warrants outstanding at March 31, 2011	5,392,820		$	1.85	$	32,129,700	4.7

Vested or expected to vest at March 31, 2011	5,392,820		$	1.85	$	32,129,700	4.7

Exercisable at March 31, 2011	5,132,861		$	1.78	$	30,900,319	4.6

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($7.80 as of March 31, 2011) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 86,875 Stock Options exercised during the nine months ended March 31, 2011 with an aggregate intrinsic value of $493,923. There were no Stock Options or Incentive Warrants that were exercised during the nine months ended March 31, 2010.

A summary of the status of our unvested Stock Options and Incentive Warrants as of March 31, 2011 and the changes during the nine months ended March 31, 2011, is presented below:

	Number of Stock Options and Incentive Warrants		Weighted Average Grant- Date Fair Value

Unvested at July 1, 2010	552,582		$	2.04

Granted	—		—

Vested	(289,498	)	$	1.99

Forfeited	(3,125	)	$	1.83

Unvested at March 31, 2011	259,959		$	2.09

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 6 — Stock-Based Incentive Plan (Continued)

During the nine months ended March 31, 2011 and 2010, there were 289,498 and 430,748 Stock Options and Incentive Warrants that vested with a total grant date fair value of $576,101 and $1,033,795, respectively.

The total unrecognized compensation cost at March 31, 2011, relating to non-vested Stock Options and Incentive Warrants was $526,777. Such unrecognized expense is expected to be recognized over a weighted average period of 0.9 years.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended March 31, 2011 and 2010 was $219,805 and $134,547, respectively. Stock-based compensation expense related to Restricted Stock grants for the nine months ended March 31, 2011 and 2010 was $601,114 and $423,969, respectively.

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2011:

	Number of Restricted Shares		Weighted Average Grant-Date Fair Value

Unvested at July 1, 2010	403,159		$	3.15

Granted	303,603		$	5.52

Vested	(161,351	)	$	3.81

Forfeited	(4,215	)	$	3.11

Unvested at March 31, 2011	541,196		$	4.28

At March 31, 2011, unrecognized stock compensation expense related to Restricted Stock grants totaled $2,207,433. Such unrecognized expense will be recognized over a weighted average period of 2.9 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 nor any accrued interest or penalties associated with unrecognized tax benefits during the nine months ended March 31, 2011. 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, 2010.

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

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 8 — Net loss Per Share

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

	Three Months Ended March 31,					Nine Months Ended March 31,
	2011		2010			2011			2010
Numerator
Net income (loss)	$	170,426	$	(551,521	)	$	(776,443	)	$	(1,958,286	)

Denominator*
Weighted average number of common shares — basic	27,521,957		27,144,174			27,379,023			26,959,713

Effect of dilutive securities:
Common stock warrants issued in connection with equity and financing transactions	110,940		—			—			—
Stock Options and Incentive Warrants	3,200,608		—			—			—
Total weighted average dilutive securities	3,311,548		—			—			—

Weighted average number of common shares and dilutive potential common shares used in diluted EPS	30,833,505		27,144,174			27,379,023			26,959,713

Net income (loss) per common share — basic	$	0.01	$	(0.02	)	$	(0.03	)	$	(0.07	)
Net income (loss) per common share — diluted	$	0.01	$	(0.02	)	$	(0.03	)	$	(0.07	)

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

Outstanding potentially dilutive securities as of March 31, 2011 are as follows:

Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at March 31, 2011

Common stock warrants issued in connection with equity and financing transactions	$	1.87	159,308
Stock Options and Incentive Warrants	$	1.85	5,392,820
Total	$	1.85	5,552,128

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

Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at March 31, 2010

Common stock warrants issued in connection with equity and financing transactions	$	1.90	171,308
Stock Options and Incentive Warrants	$	1.83	5,485,820
Total	$	1.83	5,657,128

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 9 — Commitments and Contingencies

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

Lease Commitments. We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of March 31, 2011 under this operating lease are as follows:

For the twelve months ended March 31,
2012	$	152,037
2013	159,011
2014	159,011
2015	159,011
2016	159,011
Thereafter	53,004
Total	$	841,085

Rent expense for the three months ended March 31, 2011 and 2010 was $36,808 and $36,324, respectively. Rent expense for the nine months ended March 31, 2011 and 2010 was $109,455 and $115,286, respectively.

Employment Contracts. We have entered into employment agreements with the Company’s three senior executives. The employment contracts provide for a severance package for termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination. The total contingent obligation under the employment contracts as of March 31, 2011 is approximately $524,000.

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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 2010 Annual Report on Form 10-K for the year ended June 30, 2010 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, onshore in the United States. We acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.

We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our shareholders, including approximately 20% beneficially owned by all of our directors, officers and employees.

Our strategy is intended to generate scalable, low unit cost, development and re-development opportunities that minimize or eliminate exploration risks. These opportunities involve the application of modern technology, our own proprietary technology and our specific expertise in overlooked areas of the United States.

The assets we exploit currently fit into three types of project opportunities:

· Enhanced Oil Recovery (EOR),

· Bypassed Primary Resources, and

· Unconventional Gas Development.

We expect to fund our remaining fiscal 2011 development plan from working capital and net cash flows from our properties in the Giddings and Delhi Fields, although we also may utilize appropriate financing or noncore asset sales to fund additional development above our 2011 development plan and for our 2012 development plan.

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Highlights for our Third Quarter 2011 and Project Update

Operations

· Net income turned positive at $170,426 for our third quarter fiscal 2011, compared to a $461,535 net loss in the prior quarter and a $551,521 net loss in our third quarter of fiscal 2010. For the nine month period ended March 31, 2011, we reported a net loss of $776,443, compared to a net loss of $1,958,286 for the nine month period ended March 31, 2010. Improvements were driven by a significant increase in oil production, contributions from our Giddings joint venture, an increase in average prices received per BOE, and a 75% reduction in our depletion rate due to our large addition of proved reserves as of June 30, 2010.

· Revenues in the current quarter increased 71% sequentially over the prior quarter, and 56% over the third quarter of fiscal 2010. Increased revenues were due to increases in blended product prices and oil sales volumes.

· Sales volumes continued their recent trend toward more oil, with liquid volumes (predominately crude oil) accounting for 73% of BOE sales volumes during our third quarter of fiscal 2011, compared to 65% in the prior quarter and 43% in the third quarter of fiscal 2010. Crude oil and NGL volumes increased 72% in the current three month period from the comparable prior year period. Natural gas volumes declined 53% due to normal production declines at Giddings and the temporary loss of production from our best well, the Pearson #1H, partially offset by February initial production from the Lightsey-Lightsey #1H joint venture well in which we own a 20% working interest (16% revenue interest) before payout. We believe that the Pearson #1H decline was the result of limited influx of drilling fluid water lost during the drilling of our nearby joint venture Dodd #1H well that reduced availability of gas lift gas. In mid February 2011, Pearson production was re-established at pre-loss rates. Overall sales volumes for our properties at Giddings decreased 45% as compared to the three month period ended March 31, 2010 and decreased 2% from the prior quarter.

· The blended product prices we received in the third quarter of fiscal 2011 increased 31% sequentially and 55% over the third quarter of fiscal 2010. During the quarter ended March 31, 2011 compared to the quarter ended March 31, 2010, the average prices we received increased 25% to $96.82 per barrel of oil, increased 11% to $50.31 per barrel of natural gas liquids, and decreased 28% to $3.93 per dry mcf of natural gas. On a combined basis, we realized $69.94 per BOE in the current quarter compared to $44.98 per BOE in the third quarter ended March 31, 2010.

· Field margins continued to improve to $54.85 per BOE in the third quarter of fiscal 2011, compared to $34.41 per BOE in the prior quarter and $13.63 per BOE in the third quarter of fiscal 2010. The margin improvement was driven by increased product pricing, lower lease operating expense and lower depletion rate. For the nine month period ended March 31, 2011, field margins expanded to $39.54 per BOE, compared to $8.98 for the nine month period ended March 31, 2010.

Projects

· Delhi tertiary oil volumes for the recent quarter more than doubled over the prior quarter to a gross field rate of 2,003 BO per day. Net sales to our interest averaged 148 BO per day during the current quarter, generated from our royalty interests that are free of all expense, including state severance tax until project payout. Sequentially, our sales volumes increased 113% over the second quarter of fiscal 2011 to 13,329 net BO. Phase I sales volumes accounted for approximately 98% of total volumes for the third quarter of fiscal 2011. First EOR production response from Phase I began in March of 2010, and has increased steadily.

· Delhi Phase II tertiary oil production began during March 2011. Phase II of our Delhi EOR project, which is about double the size of Phase I, began CO2 injection at the end of December 2010. First tertiary oil response occurred during March 2011, ahead of the expected mid-year 2011 first production date. Phase II oil volumes were approximately 2% of current quarter’s sales, and we expect significant increases in EOR production from Phase II during the remainder of fiscal 2011 and into 2012.

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· Phase III at Delhi is currently being installed with first CO2 injection expected during calendar 2011, with the expectation of the remaining Phases to be installed in successive years. Each of these Phases are scheduled to include similar numbers of wells as in Phase II, as compared to the much smaller Phase I.

· An oil sales pipeline connection for Delhi was completed during the quarter. Completion of the pipeline connection improved the realized oil price due to reduced transportation costs. Furthermore, changes in domestic market conditions have resulted in a premium price for Delhi’s Louisiana Light Sweet crude oil compared to oil fields in other states. During Q3-11, Delhi oil sales realized a 12% price premium over the sales price we received from Giddings in central Texas, for example. We expect that a similar market differential may continue into fiscal 2012.

· We completed infrastructure and pipelines for the second and third wells in our Joint Development Agreement. The Lightsey-Lightsey #1H was put on production in early February at an initial flowing rate of 124 BO and 1,235 MCF per day and the Dodd #1H was put on production in early April at a pipeline constrained flowing rate of approximately 2,700 MCF and 17 BO per day. Extensive gas sales lines were completed to two gas purchasers for the Dodd #1H in addition to a salt water disposal pipeline connection to our wholly owned disposal well. As previously disclosed, the JDA provides that we operate the drilling of two commitment wells on our proved locations in the Giddings Field, with the potential to add up to three option wells as elected by our partner. Under the terms of the JDA, we receive a 10% carried working interest in recognition of our costs to date, retain a 10% cost bearing working interest for our cash participation, and retain a 22.5% back-in working interest on each well drilled on our partner’s 80% working interest following a simple two well basket payout and well-by-well simple pay-out on the subsequent wells (bringing our after-payout working interest to 38%). The leases carry approximately 80% net revenue interest to the 100% working interest.

To date, we have drilled the two commitment wells and one option well and our share of capital expenditures in the JDA program to date is approximately $0.9 million. Continuation of the JDA program will depend upon our partner’s election following our pending submittal of drilling proposals for the fourth and fifth wells. We are also exploring opportunities to enter into a second joint venture to develop our remaining drilling locations.

· We continued testing of our mid-depth unconventional gas project in one well in Haskell County, OK. In Oklahoma during Q3-11, we focused on testing our 5,000’ depth unconventional gas project in the John Wells #1 well in Haskell County, a vertical well we re-entered in Q2-11. Prior to the single stage hydraulic fracturing stimulation scheduled for May 2011, the gas sales rate in the John Wells #1-28 was approximately 40-50 MCF per day while dewatering. We also are unitizing acreage around our second Haskell County test well, a vertical re-entry test well. The unitization process allows us to force unleased mineral and third party lease owners within a 640 acre section to lease or farm-out their acreage, thereby increasing our net leasehold position, or to participate as a working interest owner.

Further testing of our Wagoner County Woodford shale acreage is on hold while we focus on the bigger potential in Haskell County. To date, we have been able to establish attractive production in one of the three tested acreage blocks in Wagoner County and have elected to not exercise lease renewal options in certain blocks while maintaining our leasehold in the block containing our successful test.

· We continued pursuing commercial joint ventures utilizing our proprietary artificial lift technology. Based on tests results at Giddings, we believe our technology could re-establish production in many wells throughout Giddings and other fields developed with horizontal wells where liquids are associated with their production. We are continuing our negotiations with two third parties to demonstrate the technology with the intent of gaining an interest in the newly re-established production. The first candidate has agreed to the list of target wells and we are finalizing a joint venture agreement. Negotiations with the second candidate are less mature.

· We exercised lease options and renewed other leases. We continue to exercise lease options and renew other leases to maintain high value drilling locations at Giddings and core positions in our leasehold in Haskell County, Oklahoma.

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Finances

· We began rebuilding working capital in January 2011 as a result of sharp increases in internally generated funds from operations. We ended our first quarter with $3.1 million of working capital, compared to $4.9 million at June 30, 2010. At March 31, 2011, working capital included $3.2 million of cash, cash equivalents and short-term certificates of deposit. The $1.8 million reduction in our working capital since June 30, 2010 was due primarily to investments of $2.9 million in oil and natural gas properties, offset by an asset sale of $0.2 million and positive cash flows generated from our oil and gas properties. The asset sale included one lower valued proved undeveloped location as of June 30, 2010.

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

Liquidity and Capital Resources

At March 31, 2011, our working capital was $3.1 million, compared to working capital of $3.2 million at December 31, 2010 and $4.9 million at June 30, 2010. The $1.8 million decrease in working capital since June 30, 2010 was due primarily to investments of $2.9 million in oil and natural gas properties, offset by an asset sale of $0.2 million and positive operating cash flows. Of the $2.9 million of capital expenditures incurred during the nine months ended March 31, 2011, $0.8 million was for leasehold acquisitions and $2.1 million was for development activities. Development activities were primarily in the Giddings Field in Texas and our unconventional gas project in Eastern Oklahoma.

Cash Flows from Operating Activities

Cash flows provided by operating activities for the nine months ended March 31, 2011 were $1.5 million. Cash flows provided by operations included cash receipts of $4.3 million from oil and natural gas sales from our properties in the Giddings Field and our interests in the Delhi Field and $1.0 million due to a refund from the carry-back of our 2010 federal income tax loss. Cash payments included $3.3 million for operating expenses, including lease operating expenses, production taxes, salaries and wages, $0.3 million related to our joint interest partner’s share of capital expenditures and which are due from our joint interest partner, and $0.2 million in estimated state income taxes.

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

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2011 and 2010, was $3.1 million and $3.0 million, respectively, which includes net payments on accounts payable of $0.2 million during both periods, relating to expenditures for oil and natural gas properties. During the nine months ended March 31, 2011, we received $0.2 million for a lease sale in the Giddings Field..

During the nine months ended March 31, 2011, $1.1 million of certificates of deposit matured. During the nine months ended March 31, 2010, we purchased $1.4 million in short-term certificates of deposit and $2.1 million of certificates of deposit matured.

Cash Flows from Financing Activities

During the nine months ended March 31, 2011, we received $0.1 million due to the exercise of stock options. There were no significant cash flows from financing activities during the nine months ended March 31, 2010.

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Capital Budget

Our approved fiscal 2011 Plan provides for capital expenditures of approximately $4.0 million. We expect to fund the balance of our fiscal 2011 Plan with internally generated funds, our working capital and advances pursuant to the existing Giddings JDA. Increases in our activity level over the planned operations will be funded from joint ventures, project financing, selective divestments of noncore assets or potentially from minor non-dilutive financing vehicles as appropriate.

Results of Operations

Three month period ended March 31, 2011 and 2010

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

	Three Months Ended
	March 31							%
	2011		2010		Variance			change

Sales Volumes, net to the Company:

Crude oil (Bbl)	16,604		6,083		10,521			173	%

NGLs (Bbl)	4,533		6,217		(1,684		)	(27	)%

Natural gas (Mcf)	46,220		98,458		(52,238		)	(53	)%
Crude oil, NGLs and natural gas (BOE)	28,840		28,710		130			0	%

Revenue data:

Crude oil	$	1,607,521	$	469,418	$	1,138,103		242	%

NGLs	228,050		282,400		(54,350		)	(19	)%

Natural gas	181,504		539,563		(358,059		)	(66	)%
Total revenues	$	2,017,075	$	1,291,381	$	725,694		56	%

Average price:
Crude oil (per Bbl)	$	96.82	$	77.17	$	19.65		25	%
NGLs (per Bbl)	50.31		45.42		4.89			11	%
Natural gas (per Mcf)	3.93		5.48		(1.55		)	(28	)%
Crude oil, NGLs and natural gas (per BOE)	$	69.94	$	44.98	$	24.96		55	%

Expenses (per BOE)
Lease operating expenses and production taxes	$	10.78	$	14.12	$	(3.34	)	(24	)%
Depletion expense on oil and natural gas properties (a)	$	4.31	$	17.23	$	(12.92	)	(75	)%

(a) Excludes depreciation of office equipment, furniture and fixtures, and other of $8,215 and $10,797, for the three months ended March 31, 2011 and 2010, respectively.

Net Income. For the three months ended March 31, 2011, we reported net income of $170,426, or $0.01 per share (which includes $392,533 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $2,017,075. This compares to a net loss of $551,521, or $0.02 per share (which includes $384,701 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,291,381 for the three months ended March 31, 2010. The difference was primarily due to an increase in revenues of $725,694 and a decrease in total operating expenses of $302,349, offset by an increase in income taxes of $288,882. Additional details of the components of net income are explained in greater detail below.

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Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended March 31, 2011 remained essentially flat from the three months ended March 31, 2010, however, oil and liquids production increased from 43% of total production during the three months ended March 31, 2010 to 73% of total production during the three months ended March 31, 2011. Our crude oil sales volumes for the three months ended March 31, 2011 included 13,329 bbls from our interests in Delhi and 3,275 bbls from our properties in the Giddings Field. Our crude oil sales volumes for the three months ended March 31, 2010 included 558 bbls from our interests in Delhi and 5,525 bbls from our properties in the Giddings Field. Our NGL and natural gas volumes for the three months ended March 31, 2011 and 2010 were from our properties in the Giddings Field.

Overall sales volumes from our properties in the Giddings Field have decreased 45% from the three months ended March 31, 2010 due to normal decline and short-term loss of production from our best well, the Pearson #1H. We believe that the Pearson #1H decline was the result of influx of drilling fluid water lost during the drilling of our nearby joint venture Dodd #1H well and temporary loss of natural gas supply to drive the well’s gas lift. In February 2011, Pearson #1H production was re-established at pre-loss rates.

Petroleum Revenues. Crude oil, NGLs and natural gas revenues for the three months ended March 31, 2011 increased 56% compared to the three months ended March 31, 2010. This was due to a 55% increase in the average price received per BOE, from $45 per BOE for the three months ended March 31, 2010 to $70 per BOE for the three months ended March 31, 2011.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes for the three months ended March 31, 2011 decreased 23% compared to the three months ended March 31, 2010. The decrease was due largely to no workover costs in the current quarter compared to approximately $130,000 during the three months ended March 31, 2010. Lease operating expense and production tax per barrel of oil equivalent decreased 24% from $14.12 per BOE during the three months ended March 31, 2010, to $10.78 per BOE during the three months ended March 31, 2011.

General and Administrative Expenses (“G&A”). G&A expenses increased 14% from $1.2 million during the three months ended March 31, 2010 to $1.4 million during the three months ended March 31, 2011. The increase was due primarily to greater personnel costs associated with an increase in estimated 2011 bonuses. Stock-based compensation was $392,533 (29% of total G&A) for the three months ended March 31, 2011, compared to $384,701 (32% of total G&A) for the three months ended March 31, 2010. 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, likely will continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased by 74% to $132,516 for the three months ended March 31, 2011, compared to $505,445 for the three months ended March 31, 2010. The decrease is due to a lower depletion rate ($4.31 vs. $17.23) per BOE as a result of the addition of 9.4 million proved oil reserves at Delhi with associated legacy costs of only $1.2 million.

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Nine months ended March 31, 2011 and 2010

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

	Nine Months Ended
	March 31							%
	2011		2010		Variance			change

Sales Volumes, net to the Company:

Crude oil (Bbl)	34,670		19,781		14,889			75	%

NGLs (Bbl)	14,621		21,979		(7,358		)	(33	)%

Natural gas (Mcf)	163,735		319,154		(155,419		)	(49	)%
Crude oil, NGLs and natural gas (BOE)	76,580		94,952		(18,372		)	(19	)%

Revenue data:

Crude oil	$	3,034,333	$	1,428,915	$	1,605,418		112	%

NGLs	669,463		847,923		(178,460		)	(21	)%

Natural gas	661,807		1,385,872		(724,065		)	(52	)%
Total revenues	$	4,365,603	$	3,662,710	$	702,893		19	%

Average price:
Crude oil (per Bbl)	$	87.52	$	72.24	$	15.28		21	%
NGLs (per Bbl)	45.79		38.58		7.21			19	%
Natural gas (per Mcf)	4.04		4.34		(0.30		)	(7	)%
Crude oil, NGLs and natural gas (per BOE)	$	57.01	$	38.57	$	18.44		48	%

Expenses (per BOE)
Lease operating expenses and production taxes	$	13.12	$	12.37	$	0.75		6	%
Depletion expense on oil and natural gas properties (a)	$	4.35	$	17.22	$	(12.87	)	(75	)%

(a) Excludes depreciation of office equipment, furniture and fixtures, and other of $25,555 and $38,223, for the nine months ended March 31, 2011 and 2010, respectively.

Net loss. For the nine months ended March 31, 2011, we reported a net loss of $776,443, or $0.03 per share (which includes $1,143,413 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,365,603. This compares to a net loss of $1,958,286, or $0.07 per share (which includes $1,201,137 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $3,662,710 for the nine months ended March 31, 2010. The decrease in net loss was primarily due to an increase in revenues of $702,893 and a decrease in total operating expenses of $1,212,035, offset by a reduction of our income tax benefit of $698,334, from a benefit of 926,112 during the nine months ended March 31, 2010 to a benefit of $227,778 for the nine months ended March 31, 2011. 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 nine months ended March 31, 2011 decreased 19% from 94,952 BOE for the nine months ended March 31, 2010 to 76,580 for the nine months ended March 31, 2011. Our crude oil sales volumes for the nine months ended March 31, 2011 included 24,153 bbls from our interests in Delhi and 10,517 bbls from our properties in the Giddings Field. Our crude oil sales volumes for the nine months ended March 31, 2010 included 611 bbls from our interests in Delhi and 19,170 bbls from our properties in the Giddings Field. Our NGL and natural gas volumes for the nine months ended March 31, 2011 and 2010 were from our properties in the Giddings Field.

Overall sales volumes from our properties in the Giddings Field have decreased 44% from the nine months ended March 31, 2010 due to normal decline and the short-term loss of production from our best well, the Pearson #1H.

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Petroleum Revenues. Crude oil, NGLs and natural gas revenues for the nine months ended March 31, 2011 increased 19% compared to the nine months ended March 31, 2010. This was due to a 48% increase in the average price received per BOE, from $39 per BOE for the nine months ended March 31, 2010 to $57 per BOE for the nine months ended March 31, 2011, offset by a 19% decline in volumes. The higher price per BOE received was due to higher prices for crude oil and natural gas liquids.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes for the nine months ended March 31, 2011 decreased 15% from the nine month period ended March 31, 2010. The decrease was due to a significant reduction in saltwater disposal costs, due to our Pearson salt water disposal well, and decreased workover costs during the nine months ended March 31, 2011. Lease operating expense and production taxes per barrel of oil equivalent increased 6% from $12.37 per BOE during the nine months ended March 31, 2010, to $13.12 per BOE during the nine months ended March 31, 2011.

General and Administrative Expenses (“G&A”). G&A expenses increased 7% to $4.0 million for the nine months ended March 31, 2011, compared to $3.7 million for the nine months ended March 31, 2010. The increase was due in larger part to greater personnel costs associated with an increase in estimated 2011 bonuses and a one time recruiting charge for the hiring of a replacement field engineer, offset by a decrease in legal fees and a decrease in stock-based compensation. Stock-based compensation was $1,143,413 (29% of total G&A) for the nine months ended March 31, 2011, compared with $1,201,137 (32% of total G&A) for the nine months ended March 31, 2010. 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 79% to $358,963 for the nine months ended March 31, 2011, compared to $1,673,344 for the nine months ended March 31, 2010. The decrease is due to a lower depletion rate ($4.35 vs. $17.22) per BOE, as a result of the addition of 9.4 million proved oil reserves at Delhi with associated legacy costs of only $1.2 million.

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 in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures. During fiscal 2009 and into fiscal 2010, we saw a substantial decline in both petroleum product prices and drilling and oilfield services costs from prior years, followed by moderate increases in oil price, materials and services over the last two fiscal years. Product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties. General worldwide economic conditions continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact 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 directly seasonal, except for 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, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the third quarter ending March 31, 2011.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended March 31, 2011, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2010 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 our fiscal year ended June 30, 2010.

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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, Chief Financial and Chief Accounting Officers, 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, Chief Financial and Chief Accounting Officers concluded that as of March 31, 2011 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 March 31, 2011 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.

Table of Contents

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)

	By:	/s/ STERLING H. MCDONALD
		Sterling H. McDonald
		Vice-President and Chief Financial Officer
		Principal Financial Officer


	By:	/s/ GREG S. GOODALE
		Greg S. Goodale
		Chief Accounting Officer
		Principal Accounting Officer

Date: May 13, 2011

A.	Exhibits

	31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

	31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

	32.1	Certification of Chief Executive Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.

	32.2	Certification of Chief Financial Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.

		Page

PART I. FINANCIAL INFORMATION		2

ITEM 1.	UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	2

	Unaudited Consolidated Balance Sheets as of March 31, 2011 and June 30, 2010	2
	Unaudited Consolidated Statements of Operations for the three and nine months ended March 31, 2011 and 2010	3
	Unaudited Consolidated Statements of Cash Flows for the nine months ended March 31, 2011 and 2010	4
	Unaudited Notes to Consolidated Condensed Financial Statements	5

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

ITEM 4.	CONTROLS AND PROCEDURES	20

PART II. OTHER INFORMATION		21

ITEM 1.	LEGAL PROCEEDINGS	21

ITEM 1A.	RISK FACTORS	21

ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	21

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	21

ITEM 5.	OTHER INFORMATION	21

ITEM 6.	EXHIBITS	21

SIGNATURES		22