Evolution Petroleum (EPM) 10-Q 2013 Q3 Quarterly report

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, 2013

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)

Not Applicable

(Former name, former address and former fiscal year if changed since last report)

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: x 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 x
Non-accelerated filer o	Smaller reporting company o

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 6, 2013, was 28,620,041.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION		3
ITEM 1.	UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	3
	Unaudited Consolidated Condensed Balance Sheets as of March 31, 2013 and June 30, 2012	3
	Unaudited Consolidated Condensed Statements of Income for the three months ended March 31, 2013 and 2012 and for the nine months ended March 31, 2013 and 2012	4
	Unaudited Consolidated Condensed Statements of Cash Flows for the nine months ended March 31, 2013 and 2012	5
	Unaudited Notes to Consolidated Condensed Financial Statements	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	21
ITEM 4.	CONTROLS AND PROCEDURES	21
PART II. OTHER INFORMATION		22
ITEM 1.	LEGAL PROCEEDINGS	22
ITEM 1A.	RISK FACTORS	22
ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	22
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	22
ITEM 4.	MINE SAFETY DISCLOSURES	22
ITEM 5.	OTHER INFORMATION	22
ITEM 6.	EXHIBITS	23
SIGNATURES		24

2

PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)

	March 31,			June 30,
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	21,694,734		$	14,428,548
Certificates of deposit	250,000			250,000
Receivables
Oil and natural gas sales	2,125,506			1,343,347
Joint interest partner	10,529			96,151
Income taxes	92,885			92,885
Other	21,267			190
Deferred tax asset	162,746			325,235
Prepaid expenses and other current assets	144,149			233,433
Total current assets	24,501,816			16,769,789
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties — full-cost method of accounting, of which $5,349,286 and $6,042,094 at March 31, 2013 and June 30, 2012, respectively, were excluded from amortization	40,251,521			40,476,172
Other property and equipment	58,962			92,271
Total property and equipment	40,310,483			40,568,443
Advances to joint interest operating partner	—			1,366,921
Other assets	261,695			250,333
Total assets	$	65,073,994		$	58,955,486
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	296,845		$	407,570
Due joint interest partner	1,317,559			3,217,975
Accrued compensation	882,298			1,005,624
Royalties payable	177,942			294,013
Income taxes payable	426,693			91,967
Other current liabilities	199,805			71,768
Total current liabilities	3,301,142			5,088,917
Long term liabilities
Deferred income taxes	8,069,553			6,205,093
Asset retirement obligations	824,815			968,677
Deferred rent	57,151			70,011
Total liabilities	12,252,661			12,332,698
Commitments and contingencies (Note 11)
Stockholders’ equity
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at March 31, 2013, and June 30, 2012 with a liquidation preference of $25.00 per share	317			317
Common stock; par value $0.001; 100,000,000 shares authorized; issued 29,190,858 shares at March 31, 2013, and 28,670,424 at June 30, 2012; outstanding 28,400,041 shares and 27,882,224 shares as of March 31, 2013 and June 30, 2012, respectively	29,190			28,670
Additional paid-in capital	30,626,695			29,416,914
Retained earnings	23,069,023			18,058,909
	53,725,225			47,504,810
Treasury stock, at cost, 790,817 shares and 788,200 shares as of March 31, 2013 and June 30, 2012, respectively	(903,892		)	(882,022		)
Total stockholders’ equity	52,821,333			46,622,788
Total liabilities and stockholders’ equity	$	65,073,994		$	58,955,486

See accompanying notes to consolidated condensed financial statements.

3

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Income

(Unaudited)

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2013			2012			2013			2012
Revenues
Crude oil	$	5,947,015		$	4,532,942		$	15,331,836		$	12,212,738
Natural gas liquids	27,067			128,319			233,234			499,745
Natural gas	36,485			187,273			385,101			667,609
Total revenues	6,010,567			4,848,534			15,950,171			13,380,092
Operating Costs
Lease operating expenses	525,425			662,461			1,260,922			1,277,848
Production taxes	13,895			15,165			56,131			47,925
Depreciation, depletion and amortization	281,306			316,665			928,342			834,351
Accretion of discount on asset retirement obligations	17,232			20,124			56,090			56,712
General and administrative expenses *	1,778,178			1,560,658			5,298,878			4,454,091
Total operating costs	2,616,036			2,575,073			7,600,363			6,670,927
Income from operations	3,394,531			2,273,461			8,349,808			6,709,165
Other
Interest income	5,495			6,205			16,725			20,163
Interest (expense)	(16,308		)	(5,577		)	(49,300		)	(5,577		)
	(10,813		)	628			(32,575		)	14,586
Net income before income taxes	3,383,718			2,274,089			8,317,233			6,723,751
Income tax provision	986,676			805,989			2,801,393			2,686,778
Net Income	$	2,397,042		$	1,468,100		$	5,515,840		$	4,036,973
Dividends on Preferred Stock	168,575			168,575			505,726			461,815
Net income available to common shareholders	$	2,228,467		$	1,299,525		$	5,010,114		$	3,575,158
Basic	$	0.08		$	0.05		$	0.18		$	0.13
Diluted	$	0.07		$	0.04		$	0.16		$	0.11
Weighted average number of common shares
Basic	28,201,106			27,816,963			28,069, 285			27,759,487
Diluted	32,090,152			31,785,184			31,911,808			31,558,152

*General and administrative expenses for the three months ended March 31, 2013 and 2012 included non-cash stock-based compensation expense of $392,433 and $354,469, respectively.  For the corresponding nine month periods, non-cash stock-based compensation expense was $1,139,802 and $1,126,034, respectively.

See accompanying notes to consolidated condensed financial statements.

4

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

	Nine Months Ended March 31,
	2013			2012
Cash flows from operating activities
Net Income	$	5,515,840		$	4,036,973
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	958,566			837,673
Stock-based compensation	1,139,802			1,126,034
Accretion of discount on asset retirement obligations	56,090			56,712
Settlements of asset retirement obligations	(52,905		)	(30,969		)
Deferred income taxes	2,026,948			1,978,496
Deferred rent	(12,860		)	(11,115		)
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales	(782,159		)	(523,077		)
Receivables from income taxes and other	(21,077		)	8,346
Due to/from joint interest partner	20,105			78,110
Prepaid expenses and other current assets	89,284			(81,423		)
Accounts payable and accrued expenses	(47,339		)	32,397
Royalties payable	(116,071		)	(213,316		)
Income taxes payable	334,726			34,102
Net cash provided by operating activities	9,108,950			7,328,943
Cash flows from investing activities
Proceeds from asset sales	3,054,976			103,184
Capital expenditures for oil and natural gas properties	(4,395,350		)	(2,690,604		)
Capital expenditures for other property and equipment	—			(47,475		)
Other assets	(29,083		)	(27,295		)
Net cash used in investing activities	(1,369,457		)	(2,662,190		)
Cash flows from financing activities
Proceeds from issuances of preferred stock, net	—			6,930,535
Preferred stock dividends paid	(505,726		)	(461,815		)
Proceeds from exercises of stock options	70,500			—
Purchases of treasury stock	(21,870		)	—
Deferred loan costs	(16,211		)	(159,494		)
Net cash provided by (used in) financing activities	(473,307		)	6,309,226
Net increase in cash and cash equivalents	7,266,186			10,975,979
Cash and cash equivalents, beginning of period	14,428,548			4,247,438
Cash and cash equivalents, end of period	$	21,694,734		$	15,223,417

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2013 and 2012 are as follows:

	Nine Months Ended
	March 31,
	2013			2012
Income taxes paid	$	304,874		$	610,000
Income tax refunds received	—			28,680
Non-cash transactions:
Change in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties	(58,675		)	(97,583		)
Change in due to joint interest partner used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties	(467,978		)	—
Oil and natural gas properties incurred through recognition of asset retirement obligations	8,558			59,936

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Unaudited Notes to 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 2012 Annual Report on Form 10-K for the fiscal year ended June 30, 2012, 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., Evolution Operating Co., Inc. and Evolution Petroleum OK, 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.

Recent Accounting Pronouncements.

Liabilities.  In March 2013, the FASB issued Accounting Standards Update No. 2013-04 (ASU 2013-04), which updated the guidance in ASC Topic 405,  Liabilities.  The amendments in ASU 2013-04 generally provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the Update is fixed at the reporting date, except for obligations addressed within existing guidance in GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. The new ASU also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations.  For the Company this guidance will become effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The adoption of this guidance is not expected to have a material impact on our financial position, cash flows, or results of operations.

Offsetting Assets and Liabilities.  In January 2013, the FASB issued ASU No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies which instruments and transactions are subject to the offsetting disclosure requirements originally established by ASU 2011-11, which requires entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to a master netting or similar arrangement.  The new ASU limits the scope of the disclosures include derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  Like ASU 2011-11, the amendments in this update will be effective for fiscal periods beginning on, or after January 1, 2013. The adoption of ASU 2013-01 is not expected to have a material impact on our financial position, cash flows, or results of operations.

6

Note 2 — Property and Equipment

As of March 31, 2013 and June 30, 2012 our oil and natural gas properties and other property and equipment consisted of the following:

	March 31,2013			June 30, 2012
Oil and natural gas properties
Property costs subject to amortization	$	42,389,330		$	40,874,244
Less: Accumulated depreciation, depletion, and amortization	(7,487,095		)	(6,440,166		)
Unproved properties not subject to amortization	5,349,286			6,042,094
Oil and natural gas properties, net	$	40,251,521		$	40,476,172
Other property and equipment
Furniture, fixtures and office equipment, at cost	322,515			322,514
Less: Accumulated depreciation	(263,553		)	(230,243		)
Other property and equipment, net	$	58,962		$	92,271

Unproved properties not subject to amortization consists of unevaluated acreage and development costs of $9.2 million and $6.0 million as of March 31, 2013 and June 30, 2012, respectively, for our properties in the Mississippi Lime in Oklahoma.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.  For the nine months ended March 31, 2013, we transferred $3.8 million of  Mississippi Lime property cost to the full cost pool as initial quantities of hydrocarbon production were indicative of impairment.  During the corresponding prior year period, we transferred approximately $2.2 million of impaired assets, reflecting principally Woodford Shale properties, from our unevaluated pool to our full cost pool.

In early November 2012 the company sold its Wood well in the Giddings Field to EnerVest LLC and received net proceeds of $250,000 and the buyer’s assumption of all abandonment liabilities.

On December 24, 2012, the Company closed the sale of a portion of its producing and non-producing properties and assets in Brazos, Burleson, Fayette, Lee and Grimes Counties, Texas to ASM Oil and Gas Company, Inc. (“ASM”) for an adjusted purchase price of $2.8 million and the buyer’s assumption of all abandonment liabilities.

The proceeds from these sales were recognized as a reduction of the cost of oil and gas properties.

Note 3 — Joint Interest Agreement

Effective April 17, 2012, a wholly owned subsidiary of the Company entered into definitive agreements with Orion Exploration Partners, LLC (“Orion”) to acquire and develop interests in oil and gas leases, associated surface rights and related assets located in the Mississippian Lime formation in Kay County in North Central Oklahoma.  The Company agreed to contribute cash and a drilling carry to maintain its non-operated working interest in the joint venture.  Orion contributed the leases, its portion of the drilling capital, its operating expertise in the area and the Mississippian Lime play.  The agreement commits the parties to drill between six and fourteen gross wells by April 17, 2013. To this date, one gross salt water disposal well and two gross producer wells have been drilled and completed.

On May 1, 2013, the Company informed Orion that it has elected to forego payment of the $1.2 million remaining balance of original leasehold purchase cost, thereby reducing our joint venture interest in initial undrilled leasehold from 45% to 33.9% under the terms of the Agreement.  Either party now has the right to propose a new well within the joint venture’s area of mutual interest with the other party having the rights under a pre-agreed joint operating agreement.

Our participation in this joint venture is reflected on our March 31, 2013 and June 30, 2012 balance sheets by the items below. At March 31, 2013, the $1.3 million  due to joint interest partner balance includes a $1.2 million liability for the remaining balance of original leasehold purchase cost. Included in the $1.4 million June 30, 2012 advance to our joint interest operating partner is an accrued $1,142,716 drilling cash call, which is also reflected in the due to joint interest partner balance.

	March 31, 2013		June 30,2012
Advances to joint interest operating partner	$	—	$	$ 1,366,921
Due to joint interest partner	1,317,559		3,217,975

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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, 2013 and the year ended June 30, 2012:

	March 31, 2012			June 30, 2012
Asset retirement obligations — beginning of period	$	968,677		$	859,586
Liabilities sold	(170,433		)	—
Liabilities incurred	3,126			175,943
Liabilities settled	(38,077		)	(61,936		)
Accretion of discount	56,090			77,505
Revision of previous estimates	5,432			(82,421		)
Asset retirement obligations — end of period	$	824,815		$	968,677

Note 5 — Stockholders’ Equity

Common Stock

On July 9, 2012, a contractor of the Company net exercised 30,000 stock options for a net issuance of 15,512 shares of common stock.  The options were granted in March 2008 at an exercise price of $4.10 per share. See Note 6.

On September 6, 2012, the Board of Directors authorized and the Company issued 154,227 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $1,223,020 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 November 23, 2012, the Company issued 25,000 shares of restricted stock to a consultant who became an employee in 2013.  The value of the shares issued was $191,750, based on the fair market value on the date of issuance.  The shares vest over a two year period.  See Note 6.

On December 6, 2012, a total of 31,970 shares of our restricted common stock was issued pursuant to the 2004 Stock Plan to five outside directors as part of their annual board compensation for calendar year 2013.  The value of the shares issued was $249,973 based on the fair market value on the date of issuance.  All issuances of our common stock were subject to vesting terms per individual stock agreements, which is one year for directors.  See Note 6.

On December 20, 2012 the Company received 2,137 shares of common stock from Sterling McDonald, Vice-President and Chief Financial Officer of the Company for his payroll tax liability arising from recent vestings of restricted stock.  The $7.94 per share acquisition cost per share reflected the weighted-average market price of the Company’s shares at the dates vested.

On February 7, 2013,  a former consultant cash exercised 50,000 stock options that were granted in February 2006 at an exercise price of $1.41 per share. See Note 6.

On March 8, 2013 Sterling McDonald, Vice-President and Chief Financial Officer of the Company,  net exercised 250,000 stock options for a net issuance of 243,725 shares of common stock.  The options were granted in November 2003 at an exercise price of $0.25 per share. See Note 6.

During March 2013, the Company received 480 shares of common stock from Sterling McDonald, Vice-President and Chief Financial Officer of the Company for his payroll tax liability arising from recent vestings of restricted stock.  The $10.22 per share acquisition cost reflected the market price of the Company’s shares at the date vested.

Series A Cumulative Perpetual Preferred Stock

There were no sales during the nine months ended March 31, 2013.  During the nine months ended March 31, 2012, we sold 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock with a liquidation preference of $25.00 per share, 220,000 of which were sold in an underwritten public offering and 97,319 shares of which were sold under an at-the-market sales agreement

8

(ATM), providing aggregate net proceeds of $6,930,535  after market discounts, underwriting fees, legal and other expenses of the offerings.  The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to holders thereof.  Optional redemption can only be made by us on or after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends, or following a change of control prior to such date at redemption prices of $25.50 per share prior to July 1, 2013, and $25.25 per share from July 1, 2013 through June 30, 2014.  With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common shareholders, but subordinate to any of our existing and future debt.  Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors.

During the nine months ended March 31, 2013 and 2012, we paid dividends of $505,726 and $461,815, respectively, to holders of our Series A Preferred Stock.

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 6,500,000 shares of common stock.  No shares are available for grant under the 2003 Stock Plan and 800,914 shares remain available for grant under the 2004 Stock Plan as of March 31, 2013. We have not issued option awards since September of 2008.

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 MKT (formerly, the American Stock Exchange) in July 2006.

Stock Options and Incentive Warrants

As of August 31, 2012, all compensation costs attributable to Stock Options and Incentive Warrants had been recognized.

For the three months ended March 31, 2013 and 2012 stock-based compensation expense for Stock Options and Incentive Warrants was $- and $49,252, respectively.  For the nine months ended March 31, 2013 and 2012, such expense was $26,274 and $281,390, respectively.

There were no Stock Options or Incentive Warrants granted during the nine months ended March 31, 2013 and 2012.

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of March 31, 2013, 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, 2012	5,372,820		$	1.83
Granted	—		—
Exercised	(330,000	)	$	0.78
Cancelled or forfeited	—		—
Expired	—		—
Stock Options and Incentive Warrants outstanding at March 31, 2013	5,042,820		$	1.90	$	41,588,327	2.8
Vested or expected to vest at March 31, 2013	5,042,820		$	1.90	$	41,588,327	2.8
Exercisable at March 31, 2013	5,042,820		$	1.90	$	41,588,327	2.8

9

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($10.15 as of March 31, 2013) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 330,000 Stock Options exercised during the nine months ended March 31, 2013 with an aggregate intrinsic value of $3,000,700.

A summary of the status of our unvested Stock Options and Incentive Warrants as of March 31, 2013 and the changes during the nine months ended March 31, 2013, is presented below:

	Number of Stock Optionsand Incentive Warrants		Weighted Average Grant- Date Fair Value
Unvested at July 1, 2012	18,922		$	2.45
Granted	—		—
Vested	(18,922	)	$	2.45
Forfeited	—		—
Unvested at March 31, 2013	—		$	—

During the nine months ended March 31, 2013 and 2012, there were 18,922 and 138,248 Stock Options and Incentive Warrants that vested with a total grant date fair value of $46,359 and $295,851, respectively.

As of August 31, 2012 all compensation costs attributable to Stock Options and Incentive Warrants had been recognized.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended March 31, 2013 and 2012 was $392,433 and $305,217, respectively.  For the nine months ended March 31, 2013 and 2012, such compensation expense was $1,113,528 and $844,644, respectively.

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2013:

	Number of Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested at July 1, 2012	452,600		$	5.16
Granted	211,197		$	7.88
Vested	(215,856	)	$	5.19
Forfeited	—
Unvested at March 31, 2013	447,941		$	6.42

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For the 211,197 shares awarded above, the grant date fair value reflects the stock’s closing price on the first trading day before the grant date.  See Note 5.  At March 31, 2013, unrecognized stock compensation expense related to Restricted Stock grants totaled $2,669,957.  Such unrecognized expense will be recognized over a weighted average period of 2.4 years.

Note 7 — Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Financial Instruments.  The Company’s other financial instruments consist of cash and cash equivalents, certificates of deposit, receivables and payables. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.

Other Fair Value Measurements.  The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values, which the Company reviews quarterly.

Note 8 — 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, 2013.  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, 2012.

The Company recognized income tax expense of $986,676 and $805,989 for the three months ended March 31, 2013 and 2012,  respectively, with corresponding effective rates of 29% and 35%.

We recognized income tax expense of $2,801,393 and $2,686,778 for the nine months ended March 31, 2013 and 2012, respectively, with corresponding effective rates of 34% and 40%,  respectively.

Our effective tax rate for any period may differ from the statutory federal rate due to our state income tax liability in Louisiana, statutory depletion in excess of our tax basis, and stock-based compensation expense related to qualified incentive stock option awards (“ISO awards”), each of which creates a permanent tax difference for financial reporting.

Note 9 — Net Income Per Share

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

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	Three Months Ended March 31,				Nine Months Ended March 31,
	2013		2012		2013		2012
Numerator
Net income available to common shareholders	$	2,228,467	$	1,299,525	$	5,010,114	$	3,575,158
Denominator
Weighted average number of common shares — Basic	28,201,106		27,816,963		28,069,285		27,759,487
Effect of dilutive securities:
Common stock warrants issued in connection with equity and financing transactions	898		66,826		864		62,684
Stock Options and Incentive Warrants	3,888,148		3,901,395		3,841,659		3,735,981
Total weighted average dilutive securities	3,889,046		3,968,221		3,842,523		3,798,665
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	32,090,152		31,785,184		31,911,808		31,558,152
Net income per common share — Basic	$	0.08	$	0.05	$	0.18	$	0.13
Net income per common share — Diluted	$	0.07	$	0.04	$	0.16	$	0.11

Outstanding potentially dilutive securities as of March 31, 2013 were as follows:

Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at March 31, 2013
Common stock warrants issued in connection with equity and financing transactions	$	2.25	1,165
Stock Options and Incentive Warrants	$	1.90	5,042,820
Total	$	1.90	5,043,985

Outstanding potentially dilutive securities as of March 31, 2012 were as follows:

Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at March 31, 2012
Common stock warrants issued in connection with equity and financing transactions	$	2.50	92,635
Stock Options and Incentive Warrants	$	1.83	5,372,820
Total	$	1.84	5,465,455

Note 10 - Unsecured Revolving Credit Agreement

On February 29, 2012, Evolution Petroleum Corporation entered into a Credit Agreement (the “Credit Agreement”) with Texas Capital Bank, N.A. (the “Lender”).  The Credit Agreement provides the Company with a revolving credit facility (the “facility”) in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000.  A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit.

The facility is unsecured and has a four year term.  The Company’s subsidiaries guaranteed the Company’s obligations under the facility.  The proceeds of any loans under the facility are to be used by the Company for the acquisition and development of Oil and Gas Properties (as defined in the facility), the issuance of letters of credit, and for working capital and general corporate purposes.

Annually, the Borrowing Base and a Monthly Reduction Amount are re-determined from reserve reports.  Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender’s credit approval process, and are also limited to 25% of the value of Oil and Gas Properties.

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At the Company’s option, borrowings under the facility bear interest at a rate of either (i) an adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rate or the sum of 0.50% and the Federal Funds Rate. A maximum of three LIBOR based loans can be outstanding at any time.  Allowed loan interest periods are one, two, three and six months.  LIBOR interest is payable at the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term.  Base Rate interest is payable monthly.  Letters of credit bear fees reflecting 3.5% per annum rate applied to their principal amounts and are due when transacted.  Their maximum term is one year.

A commitment fee of 0.50% per annum accrues on unutilized availability and is payable quarterly.  The Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as for compensating the Lender $50,000 for incurred loan costs upon closing.

The Credit Agreement also contains financial covenants including a requirement that the Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1.  The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other that permitted indebtedness, and it restricts certain asset sales.  Payments of dividends for the Series A Preferred are only restricted by the EBITDA to interest coverage ratio, wherein Series A dividends are a 1X deduction from EBITDA (as opposed to a 3:1 requirement if dividends were treated as interest expense).  The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the Lender may declare all amounts outstanding under the Credit Agreement to be immediately due and payable.

As of March 31, 2013, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000.  The Company was in compliance with all the covenants of the Credit Agreement.

In connection with this agreement the Company incurred $179,468 of debt issuance costs, which have been capitalized in Other Assets and are being amortized on a straight-line basis and recorded as interest expense over the term of the agreement.

Note 11 — 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.  For legal proceedings, see “Part II, Item I. Legal Proceedings”

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, 2013 under this operating lease are as follows:

For the twelve months ended March 31,
2013	$	159,011
2014	159,011
2015	159,011
Thereafter	53,004
Total	$	530,037

Rent expense for the three months ended March 31, 2013 and 2012 was $36,808 and $36,808, respectively.  For the corresponding nine month periods of 2013 and 2012 rent expense was $110,425 and $110,425,  respectively.

Employment Contracts.  We have employment agreements with the Company’s three named executive officers.  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, 2013 is approximately $663,000.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2012 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

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 2012 Annual Report on Form 10-K for the year ended June 30, 2012 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 net asset values on a per share basis.  In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including approximately 24% 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 Reservoir Development.

We expect to fund our base fiscal 2013 development plan from working capital, with any increases to the base plan funded out of working capital, net cash flows from our properties and appropriate financing vehicles, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Highlights for our Third Quarter Fiscal 2013 and Project Update

“Q3-13” & “current quarter” is the three months ended March 31, 2013, the company’s 3th quarter of fiscal 2013.

“Q2-13” & “prior quarter” & “sequential” prior quarter is the three months ended December 31, 2012, the company’s 2nd quarter of fiscal 2013.

“Q3-12” & “year-ago quarter” is the three months ended March 31, 2012, the company’s 3th quarter of fiscal 2012.

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Operations

·Q3-13 posted record earnings per share from recurring operations*, increasing 24% sequentially and 72% over the year-ago quarter.  Increases were largely driven by the growth of crude oil’s share of revenues, causing BOE prices to increase 21%  sequentially and 24% over the year-ago quarter.

·Revenues set an all-time record, increasing 6% sequentially and 24% over the year-ago quarter despite the sale of producing properties in the Giddings Field in the prior quarter.  Crude oil volumes increased 3% sequentially and 32% over the year-ago quarter, while crude prices were 8% higher sequentially and 1% less than the year-ago quarter.

·Record crude oil volumes increased to 95% of total product volumes, compared to 82% of volumes in the prior quarter and 72% in the year-ago quarter, and Louisiana Light Sweet (“LLS”) priced volumes were an increasing proportion of total volumes reflecting the prior quarter sale of gassy properties in the Giddings Field.  Including NGL’s, liquids volumes were 97% of total volumes in the current quarter, compared to 85% in the prior quarter and 77% in the year-ago quarter.

·Field margins increased 7% sequentially and 35% over the year-ago quarter to $5.2 million.  On a BOE basis, field margins (product revenue less lifting costs, severance tax, DD&A and asset retirement expense) increased 21% sequentially and 35% over the year-ago quarter to $92/BOE.

*      Excludes the effect of a gain on an asset sale recorded in a fiscal year 2006.

Projects

Delhi EOR Project — Northeast Louisiana

·Delhi Field daily sales volumes increased 11% over the prior quarter and 40% over the year-ago quarter to a record 566 BOPD net to our 7.4% royalty interest (7,645 gross BOPD).  Sequential and comparable year-ago improvements were due to record high oil production in response to CO2 injections across a larger part of the field reflecting capital expenditures made during calendar 2011 and 2012.

·Record Delhi oil production is currently exceeding the projected level in our D&M June 2012 reserve report, potentially accelerating the working interest reversion date previously estimated for late calendar 2013.  At reversion, our net revenue interest will more than triple from 7.4% to 26.5%, while our cost bearing interest will increase from 0% to 23.9%.  The D&M report projects production to increase to approximately 11,800 gross BOPD by late 2017.

·Realized oil prices at Delhi were 7% higher sequentially and 2% lower from the year-ago quarter, averaging $111.41/BO in the current quarter.  Realized prices were $104.43/BO in the previous quarter and $113.47 in the year-ago quarter.

·Delhi’s LLS pricing continued to command a narrowing premium.  Realized Delhi prices were 13%, 16% and 20% higher than average realized oil prices in our other fields during the current, previous and year-ago quarters, respectively.

·2013 development revised.  Calendar 2013 capital expenditures proposed by the operator now target further development of the western half of the Field where the flood has already been installed. The operator is finalizing new maps of the field reservoirs incorporating extensive 3-D seismic evaluation that has identified a more complex reservoir system, and the 2013 expenditures are intended to more efficiently develop the reservoirs. We believe the new maps may quantify a portion of the upside potential in the Field not reflected in the June 2012 reserves.

Mississippian Lime — Kay County, OK

·Initial Development.  The operator completed the drilling and hydraulic fracturing and initiated dewatering of the Sneath #1H and Hendrickson #1H horizontal wells in the latter part of the prior quarter.  These wells are the first two of 114 gross probable drilling locations assigned by our independent reservoir engineer.  We own a 45% non-operating working interest in the Sneath and a 36.6% non-operating working interest in the Hendrickson, as well as a 45% working interest in a nearby salt water disposal well.

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·Mississippian Lime Background. Our play targets a limestone (carbonate) formation on the east flank of the Nemaha Ridge in central Kay County, OK, an area considered oilier and shallower than the west side of the Ridge.  Historically, both sides of the Ridge have experienced considerable vertical well development over several decades that defines the formation, while current development utilizes horizontal drilling and staged hydraulic fracture completions to increase productivity, ultimate recoveries and return on investment.

In our general area, we believe the Mississippian Limestone is a highly layered, fractured carbonate, typically with the fractures containing salt water and the matrix porosity containing hydrocarbons. In order to produce the hydrocarbons, we believe that the water within the fractures first must be produced and reservoir pressure reduced. As this occurs, hydrocarbons (being a compressible fluid) can expand out of the matrix into the high permeability fractures and then to the producing well.

·      Current drilling and completion practices.  The Sneath and Hendrickson wells were horizontally drilled by the joint venture operating partner in the middle of the formation followed by 10-12 stages of hydraulic fracturing each with the goal of fracturing the bulk of the formation matrix. The types of hydraulic fracturing utilized followed the best practices of industry in the play.  At the time of drilling, we had limited information and drilling results for wells in our area, but did observe that the two wells drilled in our area with poor reported results were located low in the formation.  In our area, horizontal wells reported by industry as successful have been drilled into the upper section of the Mississippi Lime.

·      Results to Date. Our Sneath and Hendrickson wells exhibited two characteristics we believe are prerequisites for a successful horizontal MS Lime producer, those being a large initial rate of salt water production that suggests a large reservoir, and declining bottom-hole pressures that suggest the necessary depressurization is occurring that would release the desired oil and gas production. Both wells began producing water at rates of less than 3,000 barrels per day.  The operator  gradually increased dewatering rates and reservoir pressure declined as expected with small amounts of entrained oil and gas production.  We subsequently learned from another operator of successful MS Lime wells that dewatering rates up to 10,000 barrels per day for an extended period are not unusual in our prospect area. However, to date we have not yet achieved our targeted oil and gas production rates and have been analyzing results in comparison to good and poor Mississippian Lime wells drilled by other operators. Based on this analysis, we have identified the major difference to be our laterals’ location relatively 40-50 feet lower than the wells with reported good results.

·      Next Step.  Our joint venture agreement with Orion Exploration called for a drilling commitment of at least six gross wells by mid-April 2013, only three of which had been drilled (including the disposal well).  As of April 17, 2013, that commitment had lapsed, leaving either party free to propose the drilling of additional wells within the area of mutual interest (AMI).  Accordingly, we recently proposed the drilling of a third evaluation well in the AMI to more fully test the play and our leasehold by applying the information we have learned. Spudding is expected this summer. Also subsequent to the end of the current quarter, we elected to forego payment of the remaining $1.2 million balance of the original leasehold purchase cost and reduce our JV interest in the initial leasehold not yet drilled from 45% to 33.9%.  Those funds will be redeployed to the drilling of the third producer well.

GARP®

·Our two commercial joint venture demonstrations on 3 wells in the Giddings Field continue to prove our patented technology.  Commercialization efforts for GARP®, our artificial lift technology, continue under the corporate name NGS Technologies, with fulltime staff and a separate web site, www.GARPLIFT.COM, dedicated to the business.  We reached agreement to add one well to one of the previous joint ventures.  While discussions continue with the second joint venture partner, we are in discussions with other operators to apply GARP® in oil and gas, horizontal and certain types of vertical wells in other Texas fields.

·Efforts expanded through property acquisitions.  As applications to date continue to demonstrate the effectiveness of our technology, we recently began a program to acquire abandoned wells that offer good potential for renewed production utilizing our technology.  To date, we have acquired 684 net acres in this effort associated with one well and anticipated the first related installation in June 2013.

Other Fields

·Two sales of noncore assets in the Giddings Field were completed during the previous quarter, including a portion of our producing assets and most of our undeveloped reserves in the Giddings Field.  The divested properties provided 10,534 BOE and $383,000 of revenue in Q2-13 and 13,743 BOE and $429,000 in the year-ago quarter.

·Other noncore assets in Giddings Field and South Texas are in discussions for divestment.  The remaining nonGARP® properties in the Giddings Field are tentatively scheduled for sale during our Fiscal Fourth Quarter and we are considering the sale of our Lopez Field assets due to their long lead time for development.

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Liquidity and Capital Resources

At March 31, 2013, our working capital was $21.2 million, compared to working capital of $11.7 million at June 30, 2012.  The $9.5 million increase in working capital since June 30, 2012 was due primarily to increases of $7.3 million in cash and $0.7 million in accounts receivable together with a decrease of $1.9 million in due joint interest partner.

Cash Flows from Operating Activities

For the nine months ended March 31, 2013, cash flows provided by operating activities were $9.1 million, reflecting $9.6 million provided by operations before $0.5 million was used in working capital.  Of the $9.6 million provided before working capital changes, $5.5 million was due to net income, $2.1 million from non-cash expenses and $2.0 million from deferred income taxes.

For the nine months ended March 31, 2012, cash flows provided by operating activities were $7.3 million, reflecting $8.0 million provided by operations before $0.7 million was used in working capital.  Of the $8.0 million provided, $4.0 million was attributable to net income, $2.0 million from non-cash expenses and $2.0 million from deferred income taxes.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2013 was $4.4 million.  Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and two producer wells were completed.  In Giddings, expenditures were centered on installing GARP® on a fourth commercial demonstration well.  An inflow of $3.1 million was received for proceeds from the sales of a portion of our Giddings exploration and production properties.  In December 2012, an expiring $0.25 million CD was rolled over beginning a new annual term.

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2012 was $2.7 million, primarily for development activities concentrated in the Lopez Field where four new wells were drilled with ancillary development in the Giddings Field, including a workover on the Dodd well and installation of our GARP® technology.  During the nine months ended March 31, 2012, we received $0.1 million for the sale of a portion of our Woodbine lease rights.  In December 2011, an expiring $0.25 million CD was rolled over commencing a new annual term.

Oil and gas capital expenditures incurred were $3.9 million and $2.6 million, respectively, for the nine months ended March 31, 2013 and 2012.  These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

Cash Flows from Financing Activities

In the nine months ended March 31, 2013, we paid preferred dividends of $0.5 million.

During the nine months ended March 31, 2012, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock after all offering costs and we paid $0.5 million of dividends thereon.  In connection with the unsecured revolving credit agreement entered into February 2012, the company expended deferred loan costs of $159,494.

Capital Budget

Our approved fiscal 2013 Base Plan provided for up to $10 million of capital expenditures of which $3.9 million has been incurred in the nine months ended March 31, 2013.  Due to the delay in drilling additional Mississippian Lime wells, a substantial portion of the 2013 Plan expenditures may carry over into fiscal 2014, but are elective.  For fiscal year 2014, our estimated capital maintenance expenditures, which reflect anticipated Delhi post-reversion expenditures, can be funded from our existing working capital of $21.2 million at March 31, 2013, while additional elective capital expenditures may be funded by future internally generated funds from operations (including expanded post-reversion operating cash flows from Delhi), joint ventures, project financing, selective divestments of noncore assets or other appropriate financing vehicles we believe may available to us.

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Results of Operations

Three month period ended March 31, 2013 and 2012

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

	Three Months Ended March 31,							%
	2013		2012		Variance			Change
Sales Volumes, net to the Company:
Crude oil (Bbl)	53,699		40,576		13,123			32.3	%
NGLs (Bbl)	857		3,044		(2,187		)	(71.8	)%
Natural gas (Mcf)	10,743		76,244		(65,501		)	(85.9	)%
Crude oil, NGLs and natural gas (BOE)	56,347		56,327		20			0.0	%
Revenue data:
Crude oil	$	5,947,015	$	4,532,942	$	1,414,073		31.2	%
NGLs	27,067		128,319		(101,252		)	(78.9	)%
Natural gas	36,485		187,273		(150,788		)	(80.5	)%
Total revenues	$	6,010,567	$	4,848,534	$	1,162,033		24.0	%
Average price:
Crude oil (per Bbl)	$	110.75	$	111.71	$	(0.96	)	(0.9	)%
NGLs (per Bbl)	31.58		42.15		(10.57		)	(25.1	)%
Natural gas (per Mcf)	3.40		2.46		0.94			38.2	%
Crude oil, NGLs and natural gas (per BOE)	$	106.67	$	86.08	$	20.59		23.9	%
Expenses (per BOE)
Lease operating expenses	$	9.32	$	11.76	$	(2.44	)	(20.7	)%
Production taxes	$	0.25	$	0.27	$	(0.02	)	(7.4	)%
Depletion expense on oil and natural gas properties (a)	$	4.81	$	5.38	$	(0.57	)	(10.6	)%

(a)Excludes depreciation of office equipment, furniture and fixtures, and other assets of $10,305 and $10,242, for the three months ended March 31, 2013 and 2012, respectively.

Net Income Available to Common Shareholders.  For the three months ended March 31, 2013, we generated net income of $2,228,467, or $0.07 per diluted share, (which includes $392,433 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $6,010,567.  This compares to a net income of $1,299,525, or $0.04 per diluted share, (which includes $354,469 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,848,534 for the year-ago quarter.  This increase in net income is primarily due to higher oil revenue partially offset by increased operating expenses.  Additional details of the components of net income are explained in greater detail below.

Sales Volumes.  Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended March 31, 2013 were 56,347 BOE’s compared to 56,327 BOE’s for the year-ago quarter.  Volume increases of 14,065 BOE at Delhi, 935 BOE at the Lopez Field and 682 BOE for Oklahoma were offset by a Giddings Field decrease of 15,662 BOE, of which 13,743 BOE of year-ago quarter volume were from properties that were divested in the second quarter of fiscal year 2013.

Our crude oil sales volumes for the current quarter include 50,951 barrels from our interests in Delhi and 2,748 barrels primarily from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 36,886 barrels from our interests in Delhi and 3,690 barrels from our properties in the Giddings and Lopez fields.  Our NGL volumes for the three months ended March 31, 2013 and 2012, primarily from the Giddings Field, declined 72% to 857 barrels, while natural gas volumes, virtually all produced at

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Giddings, decreased 86% to 11 MMCF from 76 MMCF in the year-ago quarter.  Declines in NGL and natural gas volumes were largely attributable to producing properties we divested in late December 2012.

Petroleum Revenues.  Crude oil, NGL and natural gas revenues totaling $6.0 million for the current quarter increased $1.2 million, or 24%, from $4.8 million in the year-ago quarter due to an increased proportion of higher value crude oil volumes.  Accordingly, blended BOE prices increased to $107 from $86 in the year-ago quarter.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the current quarter decreased $138,306 or 20%, to $539,320 compared to the year-ago quarter.  This decrease is due to higher year-ago quarter Lopez Field expense due to then recently drilled wells and salt water disposal optimization, higher year-ago Giddings Field expenses, and higher year-ago Woodford expense for wells shut in fiscal 2013, partially offset by increased expenses for Mississippi Lime wells completed in fiscal 2013.  Approximately, $102,000 of the total expense variance is attributable to Giddings properties sold in the second quarter of fiscal 2013.  Lease operating expense and production tax per barrel of oil equivalent decreased 20% from $12.03 per BOE during the year-ago quarter to $9.57 per BOE in the current quarter.

General and Administrative Expenses (“G&A”).  G&A expenses increased 14% to $1.8 million during the three months ended March 31, 2013 from $1.6 million in the year-ago quarter.  The increase reflects $175,000 for higher bonus and other personnel costs, $38,000 for increased stock compensation, $26,000 for legal and litigation expenses and $26,000 for franchise taxes, partially offset by $52, 000 of lower consulting expense.  Stock-based compensation was $392,433 (22% of total G&A) for the current quarter compared to $354,469 (23% of total G&A) for the year-ago quarter.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff 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 11% to $281,306 for the three months ended March 31, 2013, compared to $316,665 for the year-ago quarter. This decrease was due to a decline in the per BOE amortization rate, reflecting the effect of the sale of properties in the second quarter of fiscal 2013.  The current quarter’s depletion rate was $4.81 compared to $5.38 in the year-ago quarter.

Nine month period ended March 31, 2013 and 2012

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

	Nine Months Ended March 31,							%
	2013		2012		Variance			Change
Sales Volumes, net to the Company:
Crude oil (Bbl)	145,051		111,250		33,801			30.4	%
NGLs (Bbl)	6,616		9,711		(3,095		)	(31.9	)%
Natural gas (Mcf)	132,822		206,841		(74,019		)	(35.8	)%
Crude oil, NGLs and natural gas (BOE)	173,804		155,435		18,369			11.8	%
Revenue data:
Crude oil	$	15,331,836	$	12,212,738	$	3,119,098		25.5	%
NGLs	233,234		499,745		(266,511		)	(53.3	)
Natural gas	385,101		667,609		(282,508		)	(42.3	)%
Total revenues	$	15,950,171	$	13,380,092	$	2,570,079		19.2	%
Average price:
Crude oil (per Bbl)	$	105.70	$	109.78	$	(4.08	)	(3.7	)%
NGLs (per Bbl)	35.25		51.46		(16.21		)	(31.5	)%
Natural gas (per Mcf)	2.90		3.23		(0.33		)	(10.2	)%
Crude oil, NGLs and natural gas (per BOE)	$	91.77	$	86.08	$	5.69		6.6	%
Expenses (per BOE)
Lease operating expenses	$	7.25	$	8.22	$	(0.97	)	(11.8	)%
Production taxes	$	0.32	$	0.31	$	0.01		3.2	%
Depletion expense on oil and natural gas properties (a)	$	5.13	$	5.17	$	(0.04	)	(0.8	)%

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(a)Excludes depreciation of office equipment, furniture and fixtures, and other assets of $37,017 and $26,794 for the nine months ended March 31, 2013 and 2012, respectively.

Net Income Available to Common Shareholders.  For the nine months ended March 31, 2013, we generated net income of $5,010,114 or $0.16 per diluted share (which includes $1,139,802 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $15,950,171.  This compares to a net income of $3,575,158, or $0.11 per diluted share, (which includes $1,126,034 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $13,380,092 for the nine months ended March 31, 2012.  The net income increase was primarily attributable to increased oil revenue partly offset by higher operating expenses.  Additional details of earnings components 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, 2013, increased 12% to 173,804  BOE’s compared to 155,435 BOE’s for the nine months ended March 31, 2012.  This 18,369 BOE increase is primarily due to a 32% increase of 31,689 BOE at Delhi, together with a 3,262 BOE increase over the year-ago quarter’s 694 BOE at the Lopez Field, partially offset by a 16,856 BOE decline at the Giddings Field of which approximately 13,743 BOE is attributable to properties sold in the second quarter of fiscal 2013.

Our crude oil sales volumes for the nine months ended March 31, 2013 included 132,219 barrels from our interests in Delhi and 12,832 barrels principally from our properties in the Giddings and Lopez Fields.  Our crude oil sales volumes for the nine months ended March 31, 2012 included 100,530 barrels from our interests in Delhi and 10,720 barrels primarily from our properties in the Giddings and Lopez Fields.  Our NGL volumes for the nine months ended March 31, 2013 and 2012 were primarily from our properties in the Giddings Field, and declined 32% to 6,616 barrels.  For the corresponding periods, natural gas volumes, from our Giddings Field and Oklahoma properties decreased 36% to 133 MMCF.

Petroleum Revenues.  Crude oil, NGL and natural gas revenues for the nine months ended March 31, 2013 increased 19% compared to the nine months ended March 31, 2012.  This was due to 12% higher sales volumes, as mentioned above together with a 6.6%  price increase.  The average price received per BOE was $92 for the nine months ended March 31, 2013 compared to $86 for the corresponding prior year period.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes of $1,317,053 for the nine months ended March 31, 2013 decreased $8,720, or 1%, compared to $1,325,773 for the nine months ended March 31, 2012.  A decrease at Lopez Field due to higher prior year expenses for recently completed wells and salt water disposal optimization and a decline at Woodford which is shut in in the current year were partially offset by increased Mississippi Lime expenses for three wells completed in fiscal 2013.  Expenses at Giddings were essentially flat as increased current year expense for GARP wells offset the higher prior year expense, of which approximately $62,000  is attributable to properties sold in the second quarter of fiscal 2013.  Lease operating expense and production tax per barrel of oil equivalent decreased 11% from $8.53 per BOE during the nine months ended March 31, 2012, to $7.58 per BOE during the nine months ended March 31, 2013.

General and Administrative Expenses (“G&A”).  G&A expenses increased 19% from $4.5 million during the nine months ended March 31, 2012 to $5.3 million during the nine months ended March 31, 2013. The increase was due principally to $378,000 for higher bonus and other personnel costs, $178,000 of legal and litigation expenses, $79,000 for board of director fees, $77,000 for franchise tax, and $72,000 in transaction expenses related to oil and gas property sales. Stock-based compensation was $1,139,802 (22% of total G&A) for the nine months ended March 31, 2013, compared to $1,126,034 (25% of total G&A) for the nine months ended March 31, 2012.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff 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 increased by 11% to $928,342 for the nine months ended March 31, 2013, compared to $834,351 for the nine months ended March 31, 2012. The increase was primarily due to higher sales volumes as noted above.  For the nine months ended March 31, 2013 the depletion rate was $5.13 per BOE compared to $5.17 per BOE for the corresponding prior year period.

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 2013, we saw

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modest material increases in certain oil field services and materials.  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.  In addition, our lease operating expenses and their percentage of our revenues are likely to increase as our working interest production increases at our Mississippian Lime Play, reversion of our back-in working interest at Delhi or other additions to our working interest production that would dilute extraordinary margins we have enjoyed from our mineral and overriding royalty interests at Delhi.

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 quarter ending March 31, 2013.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended March 31, 2013, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2012 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, 2012.

Interest Rate Risk

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

Commodity Price Risk

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

ITEM 4. CONTROLS AND PROCEDURES

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

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2013 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in

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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.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended March 31, 2013 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 12 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2012 Annual Report. As previously reported in our Form 10-K for the fiscal year ended June 30, 2012, on March 29, 2012, the Fifth District Court of Richland Parish Louisiana dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp. brought by John C. McCarthy et. al. (the “plaintiffs”) in July 2011.  Plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006.  The trial court found that plaintiffs had “no cause of action” under Louisiana law.  The plaintiffs filed an appeal.

Since the aforementioned filing, on February 27, 2013 the State of Louisiana Court of Appeal, Second Circuit, affirmed the trial court’s judgment sustaining the exception of no cause of action in favor of the Company, but reversed the trial court’s dismissal to allow plaintiffs the opportunity to amend their petition before the trial court stating a new cause of action, if any, under a Louisiana statute not previously cited by plaintiffs.  On April 4, 2013, the Company’s request for rehearing before the Appeal Court was denied.  Accordingly, on May 3, 2013, the Company filed a Writ Application asking the Supreme Court of Louisiana to reverse the Appeal Court and reinstate the judgment of dismissal rendered by the trial court.  Grounds for relief were based in part on the Appeal Court’s gross departure from proper judicial proceedings, and in part on the Appeal Court’s misapplication of a statute (not cited by plaintiffs) to impose a new legal duty upon all mineral lessees not previously recognized by any Louisiana court in a century of jurisprudence. We believe that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on our financial position or on our results of operations.

ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 2012 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2012.

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

None.

During February 2013, the Company received 480 shares of common stock from Sterling McDonald, Vice-President and Chief Financial Officer of the Company for his payroll tax liability arising from recent vestings of restricted stock.  The acquisition cost per share reflected the weighted-average market price of the Company’s shares at the dates vested.

Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Units)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
March 1, 2013 to March 31, 2013	480 shares of Common Stock	$	10.22	Not applicable	Not applicable

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS OK except for any addl exhibits pending A&R review

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.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

EVOLUTION PETROLEUM CORPORATION

(Registrant)

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

Date: May 10, 2013

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