EVOLUTION PETROLEUM CORP - Quarter Report: 2014 March (Form 10-Q)

Outstanding Potential Dilutive Securities

Weighted
Average
Exercise Price

Outstanding at
March 31,
2014

Stock Options and Incentive Warrants

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2014

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 5, 2014, was 32,621,236.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

		Page

PART I. FINANCIAL INFORMATION		2

ITEM 1.	UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	2

	Unaudited Consolidated Condensed Balance Sheets as of March 31, 2014 and June 30, 2013	2
	Unaudited Consolidated Condensed Statements of Operations for the three months ended March 31, 2014 and 2013 and for the nine months ended March 31, 2014 and 2013	3
	Unaudited Consolidated Condensed Statements of Cash Flows for the nine months ended March 31, 2014 and 2013	4
	Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the nine months ended March 31, 2014	6
	Notes to Unaudited Consolidated Condensed Financial Statements	7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23

ITEM 4.	CONTROLS AND PROCEDURES	23

PART II. OTHER INFORMATION		23

ITEM 1.	LEGAL PROCEEDINGS	23

ITEM 1A.	RISK FACTORS	24

ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	24

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	25

ITEM 4.	MINE SAFETY DISCLOSURES	25

ITEM 5.	OTHER INFORMATION	25

ITEM 6.	EXHIBITS	26

SIGNATURES		27

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PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)

	March 31,		June 30,
	2014		2013
Assets
Current assets
Cash and cash equivalents	$	24,875,567	$	24,928,585
Certificate of deposit	—		250,000
Receivables
Oil and natural gas sales	1,544,707		1,632,853
Income taxes	214,423		281,970
Joint interest partner	383		49,063
Other	72,144		918
Deferred tax asset	15,249		26,133
Prepaid expenses and other current assets	643,055		266,554
Total current assets	27,365,528		27,436,076

Property and equipment, net of depreciation, depletion, and amortization oil and natural gas properties — full-cost method of accounting of which $4,112,704 was excluded from amortization at June 30, 2013	38,047,277		38,789,032
Other property and equipment	44,733		52,217
Total property and equipment	38,092,010		38,841,249

Advances to joint interest operating partner	—		26,059
Other assets	437,058		252,912

Total assets	$	65,894,596	$	66,556,296

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	485,951	$	642,018
Due to joint interest partner	110,393		127,081
Accrued compensation	1,075,120		1,385,494
Accrued restructuring charges	739,068		—
Royalties payable	130,022		91,427
Income taxes payable	—		233,548
Other current liabilities	674,395		153,182
Total current liabilities	3,214,949		2,632,750

Long term liabilities
Deferred income taxes	9,406,452		8,418,969
Asset retirement obligations	180,191		615,551
Deferred rent	40,006		52,865

Total liabilities	12,841,598		11,720,135

Commitments and contingencies (Note 12)

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, 2014, and June 30, 2013 with a liquidation preference of $7,932,975 ($25.00 per share)	317		317
Common stock; par value $0.001; 100,000,000 shares authorized: issued 32,571,335 shares at March 31, 2014, and 29,410,858 at June 30, 2013; outstanding 32,571,335 shares and 28,608,969 shares as of March 31, 2014 and June 30, 2013, respectively	32,571		29,410
Additional paid-in capital	33,987,802		31,813,239
Retained earnings	19,032,308		24,013,035
	53,052,998		55,856,001
Treasury stock, at cost, no shares and 801,889 shares as of March 31, 2014 and June 30, 2013, respectively	—		(1,019,840		)

Total stockholders’ equity	53,052,998		54,836,161

Total liabilities and stockholders’ equity	$	65,894,596	$	66,556,296

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
Revenues
Crude oil	$	4,280,355		$	5,947,015		$	13,216,497		$	15,331,836
Natural gas liquids	29,701			27,067			79,803			233,234
Natural gas	26,950			36,485			66,694			385,101
Total revenues	4,337,006			6,010,567			13,362,994			15,950,171

Operating Costs
Lease operating expenses	345,338			525,425			978,683			1,260,922
Production taxes	8,291			13,895			29,726			56,131
Depreciation, depletion and amortization	311,815			281,306			948,656			928,342
Accretion of discount on asset retirement obligations	9,631			17,232			34,977			56,090
General and administrative expenses *	2,304,397			1,778,178			6,875,430			5,298,878
Restructuring charges **	—			—			1,332,186			—
Total operating costs	2,979,472			2,616,036			10,199,658			7,600,363

Income from operations	1,357,534			3,394,531			3,163,336			8,349,808

Other
Interest income	7,383			5,495			22,787			16,725
Interest (expense)	(17,605		)	(16,308		)	(50,700		)	(49,300		)
	(10,222		)	(10,813		)	(27,913		)	(32,575		)

Net income before income taxes	1,347,312			3,383,718			3,135,423			8,317,233

Income tax provision	423,612			986,676			1,148,155			2,801,393

Net Income	$	923,700		$	2,397,042		$	1,987,268		$	5,515,840

Dividends on Preferred Stock	168,575			168,575			505,726			505,726

Net income available to common shareholders	$	755,125		$	2,228,467		$	1,481,542		$	5,010,114

Basic	$	0.02		$	0.08		$	0.05		$	0.18

Diluted	$	0.02		$	0.07		$	0.05		$	0.16

Weighted average number of common shares

Basic	32,358,163			28,201,106			30,328,344			28,069,285

Diluted	32,732,049			32,090,152			32,503,460			31,911,808

* General and administrative expenses for the three months ended March 31, 2014 and 2013 included non-cash stock-based compensation expense of $444,981 and $392,433, respectively. For the corresponding nine month period’s non-cash stock-based compensation expense was $1,134,841 and $1,139,802, respectively.

** Restructuring charges for the nine months ended March 31, 2014 included non-cash stock-based compensation expense of $376,365.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

	Nine Months Ended March 31,
	2014			2013
Cash flows from operating activities
Net Income	$	1,987,268		$	5,515,840
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	980,589			958,566
Stock-based compensation	1,134,841			1,139,802
Stock-based compensation related to restructuring	376,365			—
Accretion of discount on asset retirement obligations	34,977			56,090
Settlements of asset retirement obligations	(73,646		)	(52,905		)
Deferred income taxes	998,367			2,026,948
Deferred rent	(12,859		)	(12,860		)
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales	88,146			(782,159		)
Receivables from income taxes and other	(3,679		)	(21,077		)
Due to/from joint interest partner	70,083			20,105
Prepaid expenses and other current assets	(376,501		)	89,284
Accounts payable and accrued expenses	651,765			(47,339		)
Royalties payable	38,595			(116,071		)
Income taxes payable	(233,548		)	334,726
Net cash provided by operating activities	5,660,763			9,108,950

Cash flows from investing activities
Proceeds from asset sales	542,349			3,054,976
Maturity of certificate of deposit	250,000			—
Capital expenditures for oil and natural gas properties	(989,616		)	(4,395,350		)
Capital expenditures for other property and equipment	(12,793		)	—
Other assets	(181,751		)	(29,083		)
Net cash used in investing activities	(391,811		)	(1,369,457		)

Cash flows from financing activities
Proceeds on exercise of stock options	3,162,801			70,500
Cash dividends to preferred stockholders	(505,726		)	(505,726		)
Cash dividends to common stockholders	(6,462,269		)	—
Purchases of treasury stock	(1,591,765		)	(21,870		)
Windfall tax benefit	108,473			—
Recovery of short swing profits	6,850			—
Deferred loan costs	(40,334		)	(16,211		)
Net cash used in financing activities	(5,321,970		)	(473,307		)

Net increase (decrease) in cash and cash equivalents	(53,018		)	7,266,186

Cash and cash equivalents, beginning of period	24,928,585			14,428,548

Cash and cash equivalents, end of period	$	24,875,567		$	21,694,734

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2014 and 2013 are as follows:

	Nine Months Ended
	March 31,
	2014			2013
Income taxes paid	$	755,941		$	304,874

Non-cash transactions:
Change in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties	(229,062		)	(58,675		)
Change in due to joint interest partner used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties	(12,032		)	(467,978		)
Oil and natural gas properties incurred through recognition of asset retirement obligations	45,172			8,558
Previously acquired Company shares swapped by holders to pay stock option exercise price	618,606			—

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statement of Changes in Stockholders’ Equity

For the Nine Months Ended March 31, 2014

(Unaudited)

									Additional									Total
	Preferred			Common Stock					Paid-in			Retained			Treasury			Stockholders’
	Shares	Par Value		Shares		Par Value			Capital			Earnings			Stock			Equity

Balance, June 30, 2013	317,319	$	317	28,608,969		$	29,410		$	31,813,239		$	24,013,035		$	(1,019,840	)	$	54,836,161

Stock-based compensation*	—	—		—		—			1,511,206			—			—			1,511,206
Exercise of stock options	—	—		3,249,367		3,249			3,778,158			—			—			3,781,407
Exercise of stock warrants	—	—		905,391		905			(905		)	—			—			—
Issuance of restricted stock	—	—		39,732		40			(40		)	—			—			—
Forfeitures of restricted stock	—	—		(51,099	)	(51		)	51			—			—			—
Purchases of treasury stock	—	—		(181,025	)	—			—			—			(2,210,372		)	(2,210,372		)
Retirements of treasury stock	—	—		—		(982		)	(3,229,230		)	—			3,230,212			—
Net income	—	—		—		—			—			1,987,268			—			1,987,268
Common stock cash dividends	—	—		—		—			—			(6,462,269		)	—			(6,462,269		)
Preferred stock cash dividends	—	—		—		—			—			(505,726		)	—			(505,726		)
Windfall tax benefit	—	—		—		—			108,473			—			—			108,473
Recovery of short swing profits	—	—		—		—			6,850			—			—			6,850

Balance, March 31, 2014	317,319	$	317	32,571,335		$	32,571		$	33,987,802		$	19,032,308		$	—		$	53,052,998

* Includes $376,365 of stock compensation reflected in restructuring charges.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation And Consolidated 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 development of incremental oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology.

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 2013 Annual Report on Form 10-K for the fiscal year ended June 30, 2013, 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, Evolution Operating Co., Inc. Evolution Petroleum OK, Inc. and NGS Technologies, Inc. and its three wholly owned subsidiaries. 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, 2014 and June 30, 2013 our oil and natural gas properties and other property and equipment consisted of the following:

	March 31, 2014			June 30, 2013
Oil and natural gas properties
Property costs subject to amortization	$	47,136,642		$	42,772,184
Less: Accumulated depreciation, depletion, and amortization	(9,089,365		)	(8,095,856		)
Unproved properties not subject to amortization	—			4,112,704
Oil and natural gas properties, net	$	38,047,277		$	38,789,032

Other property and equipment
Furniture, fixtures and office equipment, at cost	334,901			322,514
Less: Accumulated depreciation	(290,168		)	(270,297		)
Other property and equipment, net	$	44,733		$	52,217

During the quarter ended March 31, 2014, we transferred our remaining unevaluated properties of $4.4 million in the Mississippi Lime in Oklahoma to the full cost pool. During the nine months ended March 31, 2013, we transferred $3.8 million of Mississippi Lime properties to the full cost pool as initial quantities of hydrocarbon production were indicative of impairment. At June 30, 2013 unproved property not subject to amortization consisted of unevaluated acreage of $4.1 million for our properties in the Mississippi Lime. Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

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Notes to Unaudited Consolidated Condensed Financial Statements

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. Our participation in this joint venture is reflected on our March 31, 2014 and June 30, 2013 balance sheets by the items below.

	March 31, 2014		June 30, 2013

Advances to joint interest operating partner	$	—	$	26,059
Due to joint interest partner	110,393		127,081

Note 4 — Other Current Liabilities

As of March 31, 2014 and June 30, 2013 our other current liabilities consisted of the following:

	March 31, 2014		June 30, 2013

Accrued retirement obligation	$	363,876	$	—
Asset retirement obligations due within one year	173,084		—
Accrued Louisiana franchise taxes liabilities	81,505		94,116
Accrued - other	55,930		59,066
Other current liabilities	$	674,395	$	153,182

The accrued retirement obligation of $363,876 at March 31, 2014 reflects remaining payments to be made to Sterling McDonald, the Company’s former Vice President and Chief Financial Officer, under his February 14, 2014 retirement arrangement. In February the Company recorded a $608,000 charge including $204,000 of stock compensation from the accelerated vesting of his equity awards on February 15, 2014, together with $356,000 of salary and cash incentive plan, and $48,000 of benefit payments to be paid off during the twelve months ended February 14, 2015.

Note 5 — 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 are reconciliations of the beginning and ending asset retirement obligation balances:

	March 31, 2014			June 30, 2013

Asset retirement obligations — beginning of period	$	615,551		$	968,677
Liabilities sold	(48,273		)	(439,927		)
Liabilities incurred	—			60,143
Liabilities settled	(294,152		)	(51,086		)
Accretion of discount	34,977			72,312
Revision of previous estimates	45,172			5,432
Asset retirement obligations due within one year included in “Other current liabilities”	(173,084		)	—
Asset retirement obligations — end of period	$	180,191		$	615,551

Note 6— Stockholders’ Equity

Common Stock

During the nine months ended March 31, 2014 we issued (i) 1,518,832 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $3.2 million, and (ii) 2,635,696 of our common shares upon cashless exercises of nonqualified stock options (NQSOs) and incentive warrants, all being exercised on a net basis, except for 50,956 of previously

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Notes to Unaudited Consolidated Condensed Financial Statements

acquired shares owned by option holders that were swapped in payment of the exercise price. The weighted average cost of these swapped shares was $12.14.

Additional paid-in capital increased $5.4 million, due to $1.5 million of stock compensation amortization ($0.4 million of which in the restructuring charge), $3.8 million from the exercise of stock options and warrants listed in (i) and (ii) above, and $0.1 million from tax benefits associated with stock compensation (i.e. windfall tax benefit).

Additional paid-in capital decreased by $3.2 million, due to the retirement of 801,889 shares of treasury stock acquired in previous fiscal years at a cost of approximately $1 million, and our purchase of 181,025 shares of Treasury Stock from employees and directors at an average cost of $12.21 per share or $2.2 million. 130,069 of such shares were in satisfaction of payroll tax liabilities from exercises and restricted stock vestings (requiring cash outlays by us) and 50,956 shares were received from option holders in “swap” cashless stock option exercises, using stock previously owned by the option holder. These acquisitions reduced the number of our common shares outstanding by 982,914 shares.

As the result of a common stock dividend policy approved by the Board of Directors in November 2013, March 31, 2014 retained earnings were reduced by $6.5 million of cash dividends we made to our common shareholders. Since we expect the windfall tax benefit created by the recent exercise of warrants and NQSOs will drive our tax earnings and profits account into a deficit at June 30, 2014, all cash dividends on common shares paid in fiscal 2014 will be treated for tax purposes as a return of capital and not as dividend income to the shareholder.

Recovery of Stockholder Short Swing Profit

In September 2013, an executive officer of the Company paid $6,850 to the Company, representing the disgorgement of short swing profits under Section 16(b) under the Exchange Act. The amount was recorded as additional paid-in capital.

Series A Cumulative Perpetual Preferred Stock

At March 31, 2014, there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative Preferred Stock has a liquidation preference of $25.00 per share and cannot be converted into our common stock. 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 earlier by an acquirer under a change of control at a redemption price of $25.25 per share. 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, 2014 we paid $505,726 of cash dividends to holders of our Series A Preferred Stock. Since we expect the windfall tax benefit created by the recent exercise of warrants and NQSOs will drive our tax earnings and profits account into a deficit at June 30, 2014, cash dividends for fiscal 2014 will be treated for tax purposes as a return of capital and not as dividend income to the shareholder.

Note 7 — 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 further shares are available for grant under the 2003 Stock Plan and 812,281 shares remain available for grant under the 2004 Stock Plan as of March 31, 2014.

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 our success and to remain in our service (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

For the nine months ended March 31, 2014 and 2013, stock-based compensation expense related to stock options and incentive warrants was $-0- and $26,274, respectively. As of August 31, 2012 all compensation costs attributable to Stock Options and Incentive Warrants had been recognized.

No Stock Options or Incentive Warrants have been granted since August 2008.

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Notes to Unaudited Consolidated Condensed Financial Statements

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of March 31, 2014, 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, 2013	4,822,820		$	1.99

Exercised	(4,594,759	)	$	1.99

Stock Options and Incentive Warrants outstanding at March 31, 2014	228,061		$	2.02	$	2,443,524	1.79

Vested or expected to vest at March 31, 2014	228,061		$	2.02	$	2,443,524	1.79

Exercisable at March 31, 2014	228,061		$	2.02	$	2,443,524	1.79

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($12.73 as of March 31, 2014) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 4,594,759 Stock Options and Warrants exercised during the nine months ended March 31, 2014 with an aggregate intrinsic value of $47,011,615.

During the nine months ended March 31, 2013 there were 18,922 Stock Options and Incentive Warrants that vested with a total grant date fair value of $46,359 and no unvested Stock Options and Incentive Warrants remained.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended March 31, 2014 and 2013 was $444,981 and $392,433, respectively. For the nine months ended March 31, 2014 and 2013, such compensation expense was $1,134,841 and $1,113,528 respectively. See Note 13 — Restructuring, for stock compensation included in Restructuring Charge for the nine months ended March 31, 2014.

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2014:

	Number of Restricted Shares		Weighted Average Grant-Date Fair Value

Unvested at July 1, 2013	386,599		$	6.65

Granted	39,732		12.58

Vested	(255,326	)	$	6.45

Forfeited	(9,066	)	$	5.98

Unvested at March 31, 2014	161,939		$	8.45

At March 31, 2014, unrecognized stock compensation expense related to Restricted Stock grants totaled $1,219,792. Such unrecognized expense will be recognized over a weighted average period of 2.2 years.

Note 8 — 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.

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Notes to Unaudited Consolidated Condensed Financial Statements

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 we review quarterly.

Note 9 — 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 FIN 48 unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the nine months ended March 31, 2014. We believe we have appropriate support for the income tax positions taken and to be taken on our 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, 2009 through June 30, 2013.

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

Our estimated annual income tax rate used to determine income tax expense for the nine months ended March 31, 2014 does not include the utilization of statutory depletion deductions in excess of basis carried over from previous years that had driven our book tax rate well below statutory rates during the three months ended September 30, 2013. Instead our tax benefits were changed significantly during November and December 2013 when our employees, officers and directors exercised more than 4 million of 4.8 million stock options and incentive warrants, resulting in approximately $31.2 million of expected tax deductions (“Option Deductions”) available to us resulting in a tax impacted benefit of approximately $10.6 million assuming a 34% statutory rate. On a financial reporting basis, this is expected to result in a tax benefit associated with stock compensation (i.e. windfall tax benefit) to the extent of expected cash income taxes payable generated in fiscal year 2014. The remainder of the Option Deductions result in an unbenefitted net operating loss associated with stock compensation to benefit future fiscal years. To the extent the Option Deductions cause a net operating loss, no deferred tax asset is recorded under the rules of ASC 718. The Option Deductions will be recorded as a reduction in current income taxes payable each year and an increase in equity to the extent cash taxes payable are reduced to zero.

Because the Option Deductions are expected to reduce taxable income to zero for the year ended June 30, 2014, percentage depletion is no longer available for the current year, thus negating the beneficial rate reduction for the percentage depletion in excess of basis. Percentage depletion that is no longer expected to be deductible in 2014, will be carried forward to future years. The Option Deductions will only impact reported earnings by increasing the projected effective tax rate closer to the statutory rate in those years affected by the Option Deductions due to percentage depletion in excess of basis deduction being delayed and carried forward. Our effective annual tax rate estimated as March 31, 2014 was impacted by this postponement of depletion in excess of basis. Our estimated annual income tax rate used to determine income tax expense for the three months ended September 30, 2013 included the utilization of statutory depletion deductions carried over from previous years resulting in a higher than normal rate benefit from depletion in excess of basis which has been reversed in the current fiscal quarter.

We recognized income tax expense of $1,148,155 and $2,801,393 for the nine months ended March 31, 2014 and 2013, respectively, with corresponding effective rates of 37% and 34%.

Note 10 — Net Income Per Share

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

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Notes to Unaudited Consolidated Condensed Financial Statements

	Three Months Ended March 31,				Nine Months Ended March 31,
	2014		2013		2014		2013
Numerator
Net income available to common shareholders	$	755,125	$	2,228,467	$	1,481,542	$	5,010,114

Denominator

Weighted average number of common shares — Basic	32,358,163		28,201,106		30,328,344		28,069,285

Effect of dilutive securities:
Common stock warrants issued in connection with equity and financing transactions	—		898		—		864
Stock Options and Incentive Warrants	373,886		3,888,148		2,175,116		3,841,659
Total weighted average dilutive securities	373,886		3,889,046		2,175,116		3,842,523

Weighted average number of common shares and dilutive potential common shares used in diluted EPS	32,732,049		32,090,152		32,503,460		31,911,808

Net income per common share — Basic	$	0.02	$	0.08	$	0.05	$	0.18
Net income per common share — Diluted	$	0.02	$	0.07	$	0.05	$	0.16

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Notes to Unaudited Consolidated Condensed Financial Statements

Outstanding potentially dilutive securities as of March 31, 2014 were as follows:

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	$	1.82	5,342,820
Total	$	1.82	5,343,985

Note 11 - 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 us 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. Our subsidiaries guaranteed the Company’s obligations under the facility. We may use the proceeds of any loans under the facility 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.

Semi-annually, the Borrowing Base and a Monthly Reduction Amount are re-determined from reserve reports. Requests by us 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 (as defined) of our Oil and Gas Properties.

At our 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. We are 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 we 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, 2014, we 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 Lender waived the provisions of the Credit Agreement pertaining to the past payments of cash dividends on our common stock.

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

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Notes to Unaudited Consolidated Condensed Financial Statements

Note 12 — 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. At a minimum 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 accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that 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. We expense legal defense costs as they are incurred. For legal proceedings, see “Part II, Item 1. Legal Proceedings.”

Lease Commitments. We have a non-cancelable operating lease for office space that expires on July 31, 2016. Future minimum lease commitments as of March 31, 2014 under this operating lease are as follows:

For the twelve months ended March 31,
2015	$	159,011
2016	159,011
2017	53,004
Total	$	371,026

Rent expense for the three months ended March 31, 2014 and 2013 was $44,473 and $36,808, respectively. For the corresponding nine month periods of 2014 and 2013 rent expense was $131,151 and $110,425, respectively.

Employment Contracts. We have employment agreements with two named executive officers. The employment contracts provide for a severance package for termination by us 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, 2014 is approximately $591,000.

Delhi Payout. We are presently in a dispute with the Delhi Field Operator concerning charges arising from the environmental event that began in June 2013. We believe the Operator has indemnified us for such events, with the effect that payout should not be delayed. To date, the Operator has not agreed to the application of the indemnity and their 2006 assumption of environmental liabilities. Accordingly, we have filed a lawsuit against the Operator seeking declaration of the validity of the 2006 agreements, including the indemnity, and recovery of damages and attorney’s fees. The Operator subsequently filed counterclaims.

Note 13 — Restructuring

On November 1, 2013, we undertook an initiative refocusing our business to GARP® development that resulted in adjustment of our workforce towards less emphasis on engineering and greater emphasis on sales and marketing. In exchange for non-compete agreements with the terminated employees, we recorded a restructuring charge of approximately $1,332,000 representing $376,000 of stock-based compensation from the accelerated vesting of equity awards and $956,000 of accrued estimated salary, cash incentive plan and benefits to be paid off during the twelve months ended December 31, 2014. Our current estimate of remaining accrued restructuring charges as of March 31, 2014 are as follows:

Type of Cost	Balance at December 31, 2013		Payments			Balance at March 31, 2014

Salary Expense	$	615,721	$	(153,930	)	$	461,791
Cash Incentive Plan	185,525		—			185,525
Other Benefits	154,575		(62,823		)	91,752
Accrued Restructuring Charges	$	955,821	$	(216,753	)	$	739,068

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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, 2013 (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 (the “Securities Act”) 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 2013 Annual Report on Form 10-K for the year ended June 30, 2013 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 engaged primarily in the development of incremental oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology.

We particularly focus 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 a substantial ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership of our common stock.

Our strategy is intended to fully participate in growing the value of our Delhi asset and maximize the value realized by our shareholders from that asset while aggressively commercializing our patented GARP® technology for recovering incremental oil and gas reserves in mature fields.

We are funding our base fiscal 2014 development plan from working capital, with any increases to the base plan funded out of working capital and net cash flows from our properties.

Highlights for our Third Quarter Fiscal 2014 and Project Update

“Q3-14” & “current quarter” is the three months ended March 31, 2014, the company’s 3rd quarter of fiscal 2014.

“Q2-14” & “prior quarter” is the three months ended December 31, 2013, the company’s 2nd quarter of fiscal 2014.

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

Operations

· For Q3-14, we returned to profitability with net income of $0.8 million, impacted by a one-time charge of $0.6 million for the retirement of our previous CFO, compared to net loss of $0.6 million in the prior quarter and net income of $2.2 million in the year-ago quarter. The current quarter’s earnings increase was primarily due to the prior quarter’s $1.3 million restructuring charge and $0.8 million of non-recurring charges. The decrease from the year-ago quarter is primarily due to lower oil revenue and higher G&A, including the one-time $0.6 million charge, partially offset by lower LOE and income taxes.

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· Current quarter revenue of $4.3 million was flat sequentially and a decrease of 28% from $6.0 million in the year-ago quarter. The decrease from the year-ago quarter is primarily due to lower Delhi revenue driven by lower volumes and prices, as well as the fiscal 2013 divestment of Giddings properties and Q2-14 divestment of Lopez properties, offset by increased GARP® production.

· Black oil volumes accounted for 96% of total volumes and 99% of revenues during Q3-14, compared sequentially to 96% of volume and 99% of revenues in the prior quarter, while the year-ago quarter’s oil volume was 95% of volume and 99% of revenue. Delhi oil volumes decreased 4% from the prior quarter and decreased 19% compared to the year-ago quarter. The sequential decrease in Delhi production primarily reflects two fewer production days, resulting in daily volumes being essentially flat compared to the previous quarter.

· The blended oil, NGL and natural gas product price we received in Q3-14 increased 6% sequentially to $99.03 per BOE from $93.66 in the prior quarter, and decreased 8% from $106.67 in the year-ago quarter. Current quarter oil prices increased 5% sequentially to $101.65 and decreased 9% compared to the year-ago quarter. Our average oil price reflects the large proportion of sales from Delhi that received favorable Louisiana Light Sweet pricing. The current quarter’s price spread to WTI was 4%, compared to 2% sequentially and 13% in the year-ago quarter. NGL price increased 27% sequentially and 23% from the year-ago quarter to $38.88, while natural gas price increased 52% sequentially and 43% compared to the year-ago quarter to $4.87.

· A one-time charge of $0.6 million was recorded in the current quarter related to the February retirement of our previous CFO. This charge to G&A included $0.2 million of non-cash stock compensation expense and $0.4 million for payments to be made over the next year for salary, cash incentive and benefits.

· $1.0 million of proceeds were received during the current quarter from stock option exercises.

Delhi EOR Project

· Production in our Delhi enhanced oil recovery project of 457 BOPD net to our 7.4% royalty interest (6,172 gross BOPD) was essentially flat compared to the previous quarter and a decrease of 19% from the year-ago quarter. The decrease from the year ago quarter was due to the continuing production impact of the remediation work during the second half of calendar 2013 in response to a June 2013 fluids release event. As part of the remediation, the operator temporarily suspended CO2 injection in the southwestern portion of the field near the discovered fluid release in order to reduce reservoir pressure to stop further releases and allow re-entry of the previously plugged well(s) believed to be the source of the fluids release. This reduction in CO2 injection volumes that “drives” tertiary oil production temporarily reduced production in that area. Recently, the operator announced that remediation work had been completed and incremental CO2 injection resumed, although CO2 injection in the area directly impacted by the well believed to be the source of the fluids release has been replaced with water injection, a conventional secondary recovery technique. At this time, we do not know how much of the production rate decrease will be restored or the impact on future production and reserves due to the operator’s revised development plan.

The operator recently announced that the field was back to normal operations and that it planned net development capital expenditures during calendar 2014 totaling $40 million. The operator further announced its plan to begin constructing a gas processing plant to recover methane and natural gas liquids from the recycle gas stream with first operations in 2015.

The temporary decline in production combined with the remediation expense has delayed the reversion of our 24% working interest to later in calendar 2014, excluding the effect of any indemnity of, or compensation to, us or the payout account by the operator, or the receipt of any insurance reimbursements. To date, the operator has not agreed to our interpretation of the application of the indemnity and their 2006 assumption of environmental liabilities and obligations, and we have filed a lawsuit against the operator seeking, among other things, declaration of the validity of the 2006 agreements that include the indemnity and recovery of damages and attorney’s fees. The lawsuit asserts various breaches of the 2006 purchase and sale agreements and operating agreements between us and the operator including improperly charging our payout account for the cost of its remediation work, failure to timely assign us our reversionary working interest due to un-allowed charges to the deemed payout account, failure to indemnify us for damages associated with reductions in production due to the environmental event in June 2013, charging our payout account $43.8 million through March 31, 2014 for the cost of the processing plant as an operating cost and not a capital cost, charging over $2.4 million of plugging and abandonment cost as operating expense and not as capital, and failure to offer us our pro

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rata share of acquisitions made by the operator within the area of mutual interest. The Operator subsequently filed counterclaims.

Our working interest reversion, when it occurs, will more than triple our revenue interest from 7.4% to approximately 26.5%, while our cost bearing interest will increase from 0% to 23.9%.

· Realized oil prices at Delhi increased 5% sequentially and decreased 10% from the year-ago quarter to $102 per BO. Realized prices were $97 per BO in the previous quarter and $111 per BO in the year-ago quarter.

· The operator has stated its intention to begin work in 2014 on a plant to recover methane and natural gas liquids from the recycle gas stream with completion in calendar 2015; the plant would have a broader recovery of liquids and an earlier start date than projected in our June 30, 2013 reserve report. The plant is expected to have a positive impact on reserves, offset by any impact of the June 2013 fluids release. Proved oil reserves net to our interest are 74% developed and probable reserves are 48% developed as of June 30, 2013, based on our independent engineer’s report as filed in our 2013 Form 10-K.

GARP® (Gas Assisted Rod Pump)

· We entered into an agreement during the quarter with a large independent operator to install GARP® in ten wells in the Giddings Field. The operator has the option to terminate the second five installations based on uneconomic performance in the first five installations. We will pay for the intangible costs of installation and a portion of required new tubing, and the operator will provide the leases and wells fully equipped for pumped operations as well as the balance of required new equipment. We will earn a fee equal to twenty-five percent of the field cash profits from the wells. The operator has a substantial portfolio of similar candidates for installation of GARP® that could be added to our agreement in the future.

· Subsequent to the end of the quarter and following our work with the customer to design the implementation of GARP® in the targeted wells, the operator has begun installing GARP® in the first five wells.

· The first three of the current commercial GARP® installations continue to perform as expected. The fourth installation, the Appelt, has experienced the same fines production that caused pump plugging problems prior to installation of GARP®, and the high operating cost associated with repeatedly cleaning out the fines has offset the increased production due to our GARP® installation.

· Our GARP® technology was awarded the 43rd annual E&P Special Meritorius Award for Engineering Innovation for 2014. The presentation of the award was made recently at the Offshore Technology Conference in Houston, and the award recognized the technology’s innovation, suitability as a practical solution and potential for improving efficiency and profitability.

Projects — Non-Core Assets

Mississippi Lime

· Testing has been completed in the recompleted Sneath well, in which we plugged off production from the first 2/3rds of the horizontal lateral that is lowest in section in order to test production from a structurally higher portion of the reservoir. Results suggest that the recompletion was unsuccessful in completely shutting off water from the lower section of the horizontal section, thus we cannot prove or disprove the production model. At this time, no further development is under consideration and we are evaluating our options for this asset including divestment.

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Looking Forward

· $0.1 million of cash proceeds from the exercise of ISO’s will be recorded in FQ4-14. In April, an officer exercised 50,000 stock options.

· We expect to achieve first production during Q4-14 from the first group of GARP® installations under the contract announced in Q3-14.

· Financial results will not be burdened by restructuring and related nonrecurring charges.

· Dividends paid to common and preferred shareholders through our year ending June 30, 2014 will be reported as return of capital and not as taxable dividends to the recipient.

Liquidity and Capital Resources

At March 31, 2014, our working capital was $24.2 million, compared to working capital of $24.8 million at June 30, 2013. The $0.6 million decrease in working capital since June 30, 2013 was due primarily to payment of $6.5 million of common stock dividends paid during our second and third fiscal quarters and increased current liabilities reflecting one-time accruals for restructuring charges and a retirement obligation, mostly offset by cash flows from operating activities, exercises of stock options and warrants, and lower accounts payable and accrued compensation.

Cash Flows from Operating Activities

For the nine months ended March 31, 2014, cash flows provided by operating activities were $5.7 million, reflecting $5.4 million provided by operations before $0.2 million provided by other working capital changes. Of the $5.4 million provided before working capital changes, $2.0 million was due to net income, which includes $1.3 million of restructuring and $0.6 million of retirement obligation charges, and $3.4 million was attributable to non-cash expenses.

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.

The decrease in cash flow from operations for the nine months ended March 31, 2014 as compared to the nine months ended March 31, 2013 was due primarily to $2.6 million of lower revenue reflecting reduced Delhi Field production due to the fluids release together with $1.4 million of current year non-recurring items and a $1.3 million restructuring charge.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2014 was $1.0 million. Development activities were about equally divided between GARP® wells in Giddings and the Sneath and Hendrickson wells completed in the Mississippi Lime during the prior year. We received approximately $542,000 of proceeds from asset sales, including $400,000 from the prior quarter sale of our South Texas properties, and $250,000 of cash from the maturity of a certificate of deposit.

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.

Oil and gas capital expenditures incurred, but not yet paid, were $0.8 million and $3.9 million, respectively, for the nine months ended March 31, 2014 and 2013. 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.

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Cash Flows from Financing Activities

In the nine months ended March 31, 2014, we used $5.3 million in cash for financing activities, including cash inflows of $3.2 million from stock option exercise proceeds and $0.1 million of windfall tax benefits, offset by cash outflows of $6.5 million for common dividends, $0.5 million for preferred dividends and $1.6 million for treasury stock purchases related to incentive stock warrant and stock option exercises and restricted stock vestings.

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

Capital Budget

We expect to fund all of our remaining fiscal 2014 Capital Plan, the total of which is uncertain at this time, with our $24.2 million of working capital on hand at March 31, 2014 and internally generated funds from operations. Our current capital budget for the balance of 2014 includes the potential of up to $10 million of development expenditures at Delhi, subject to the actual reversion date of our working interest and the timing of capital expenditures by the operator during calendar 2014. Our GARP® business is expected to require up to approximately $1 million during the balance of 2014, depending upon the timing of our customer’s approval for and execution of the second five installations, as well as any other installations under any new agreement. No capital is currently allocated for the Mississippian Lime assets.

Capital Outlook for FY15

With reversion of our 23.9% working interest in Delhi expected to occur during FY15, we expect to begin funding our share of capital expenditures upon reversion. Although not yet established, the capital budget for Delhi for calendar 2015 is estimated to be approximately $12-20 million, thus our capital budget for fiscal 2015 may approach $22-30 million, depending upon the timing of expenditures by the operator and reversion date. Capital expenditures in our GARP® activities are expected to be less than $5 million for 2015. Funding for all capital expenditures is expected to be met from current working capital and cash flows from operations. In addition, we have access to a $5 million unsecured revolver and are in discussions to convert the revolver to a senior secured credit with up to $30 million of capacity, primarily to provide a standby source of liquidity to meet future lump sum capital expenditures at Delhi.

Results of Operations

Three month period ended March 31, 2014 and 2013

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

	Three Months Ended March 31,							%
	2014		2013		Variance			Change

Sales Volumes, net to the Company:

Crude oil (Bbl.)	42,108		53,699		(11,591		)	(21.6	)%

NGLs (Bbl.)	764		857		(93		)	(10.9	)%

Natural gas (Mcf)	5,532		10,743		(5,211		)	(48.5	)%
Crude oil, NGLs and natural gas (BOE)	43,794		56,347		(12,553		)	(22.3	)%

Revenue data:

Crude oil	$	4,280,355	$	5,947,015	$	(1,666,660	)	(28.0	)%

NGLs	29,701		27,067		2,634			9.7	%

Natural gas	26,950		36,485		(9,535		)	(26.1	)%
Total revenues	$	4,337,006	$	6,010,567	$	(1,673,561	)	(27.8	)%

Average price:
Crude oil (per Bbl.)	$	101.65	$	110.75	$	(9.10	)	(8.2	)%
NGLs (per Bbl.)	38.88		31.58		7.30			23.1	%
Natural gas (per Mcf)	4.87		3.40		1.47			43.2	%
Crude oil, NGLs and natural gas (per BOE)	$	99.03	$	106.67	$	(7.64	)	(7.2	)%

Expenses (per BOE)
Lease operating expenses	$	7.89	$	9.32	$	(1.43	)	(15.3	)%
Production taxes	$	0.19	$	0.25	$	(0.06	)	(24.0	)%
Depletion expense on oil and natural gas properties (a)	$	6.90	$	4.81	$	2.09		43.5	%

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(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $9,732 and $10,305, for the three months ended March 31, 2014 and 2013, respectively.

Net Income Available to Common Shareholders. For the three months ended March 31, 2014, we earned net income of $0.8 million or $0.02 per diluted share, (which includes a pre-tax $0.6 million non-recurring charge for a retirement obligation) on total oil and natural gas revenues of $4.3 million. The current quarter’s non-cash stock compensation expense was $444,981 of which $203,861 related to the accelerated vesting of equity awards under the retirement arrangement. This compares to the year ago 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. Decreased revenues and higher general and administrative expense were partially offset by lower lease operating expenses and income tax expense.

Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended March 31, 2014 decreased 22% to 43,794 BOE’s compared to 56,347 BOE’s for the year-ago quarter. This 12,553 volume decrease primarily reflects lower Delhi Field volumes, lower Giddings Field volumes due to sale of properties in fiscal 2013 and the absence of Lopez field volumes (sold in December 2013). Our crude oil sales volumes for the current quarter of 42,108 barrels include 41,137 from our interests in Delhi and 966 barrels from the Giddings field. Our crude oil sales volumes for the year-ago quarter of 53,699 barrels included 50,951 barrels from our interests in Delhi, 1,264 barrels at Giddings, 1,218 barrels at Lopez and 266 barrels at the Mississippi Lime. Our NGL volumes for the three months ended March 31, 2014 declined 11% to 764 barrels compared to 857 barrels in the year-ago-quarter. Current quarter natural gas volumes, virtually all produced at Giddings, decreased 49% to 5,532 mcf from 10,743 mcf in the year-ago quarter. Both NGL and natural gas volumes were impacted by the Giddings sales.

Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $1.7 million to $4.3 million for the current quarter, a 28% decrease from $6.0 million in the year-ago quarter due to a 22% volume decline together with a 7% lower price per BOE. Prices per BOE were $99.03 and $106.67, respectively, for the current and year-ago quarters.

Lease Operating Expenses (including ad valorem and production severance taxes). Lease operating expenses and production taxes for the current quarter decreased $185,691, or 34%, to $353,629 compared to the year-ago quarter. Expenses were approximately $106,000 lower due to the Lopez Field sale, $35,000 lower at our Mississippi Lime properties, and $44,000 lower in the Giddings Field where the impact of fiscal 2013 divestitures was partially offset by higher expenses at GARP® wells. Lease operating expense and production tax per barrel of oil equivalent decreased 16% from $9.57 per BOE during year-ago quarter to $8.08 per BOE during current quarter.

General and Administrative Expenses (“G&A”). G&A expenses increased $0.5 million, or 30%, to $2.3 million during the three months ended March 31, 2014 from $1.8 million in the year-ago quarter primarily due to a $0.6 million non-recurring charge related to the retirement of the Company’s vice president and chief financial officer. The charge consisted of $0.2 million of stock compensation from the accelerated vesting of equity awards, $0.3 million for future payments of salary and benefits and $0.1 million for cash incentive bonus. Stock-based compensation was $444,981 (19% of total G&A) for the current quarter compared to $392,433 (22% of total G&A) for the year-ago quarter.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased 11% to $311,815 for the three months ended March 31, 2014, compared to $281,306 for the year-ago quarter. This change was principally due to a 40% increase in depletion rate from $4.81 per BOE in the year-ago quarter to $6.72 in the current quarter partially offset by a 22% decline in volume as described above. Much of the higher depletion rate is due to higher future capital expenditures at Delhi associated with increased reserves reflected in our June 30, 2013 reserve report.

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Nine month period ended March 31, 2014 and 2013

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

	Nine Months Ended March 31,							%
	2014		2013		Variance			Change

Sales Volumes, net to the Company:

Crude oil (Bbl.)	128,853		145,051		(16,198		)	(11.2	)%

NGLs (Bbl.)	2,408		6,616		(4,208		)	(63.6	)%

Natural gas (Mcf)	18,442		132,822		(114,380		)	(86.1	)%

Crude oil, NGLs and natural gas (BOE)	134,335		173,804		(39,469		)	(22.7	)%

Revenue data:

Crude oil	$	13,216,497	$	15,331,836	$	(2,115,339	)	(13.8	)%

NGLs	79,803		233,234		(153,431		)	(65.8	)%

Natural gas	66,694		385,101		(318,407		)	(82.7	)%
Total revenues	$	13,362,994	$	15,950,171	$	(2,587,177	)	(16.2	)%

Average price:
Crude oil (per Bbl.)	$	102.57	$	105.70	$	(3.13	)	(3.0	)%
NGLs (per Bbl.)	33.14		35.25		(2.11		)	(6.0	)%
Natural gas (per Mcf)	3.62		2.90		0.72			24.8	%
Crude oil, NGLs and natural gas (per BOE)	$	99.48	$	91.77	$	7.71		8.4	%

Expenses (per BOE)
Lease operating expenses	$	7.29	$	7.25	$	0.04		0.6	%
Production taxes	$	0.22	$	0.32	$	(0.10	)	(31.3	)%
Depletion expense on oil and natural gas properties (a)	$	6.87	$	5.13	$	1.74		33.9	%

(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $25,875 and $37,017 for the nine months ended March 31, 2014 and 2013, respectively.

Net Income Available to Common Shareholders. For the nine months ended March 31, 2014, we generated net income of $1,481,542 or $0.05 per diluted share, (which includes a $1.3 million restructuring charge, $1.4 million of non-recurring charges related to prior quarter stock option exercises and the current quarter retirement of the Company’s chief financial officer) on total oil and natural gas revenues of $13,362,994. For the nine months ended March 31, 2014, non-cash stock compensation expense was $1,134,841 of which $203,861 related to the retirement charge. This compares to a 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 for the corresponding year-ago period. The earnings decline is due to lower revenue, higher G&A, and a current year restructuring charge, partially offset by lower lease operating expense and income taxes. 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 nine months ended March 31, 2014 decreased 23% to 134,335 BOE’s compared to 173,804 BOE’s for the year-ago period. This 39,469 volume decrease is due to a 27,930 BOE Giddings volume decrease (reflecting properties sold in fiscal 2013 partially offset by improved GARP® production), an 8,130 Delhi decrease, lower Lopez volume of 2,708 and a decline of 701 at Mississippi Lime. Our crude oil sales volumes for the nine

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months ended March 31, 2014 include 124,089 from our interests in Delhi and 3,382 barrels from the Giddings and 1,248 barrels from Lopez fields. Our crude oil sales volumes for the corresponding year-ago period included 132,219 barrels from our interests in Delhi and 8,393 barrels from Giddings and 3,956 barrels from Lopez field. Our NGL volumes for the nine months ended March 31, 2014 declined 64% to 2,408 barrels compared to 6,616 barrels in the year-ago period. Current period natural gas volumes, virtually all produced at Giddings, decreased 86% to 18,442 mcf from 132,822 mcf for in the nine months ended March 31, 2013.

Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $2.6 million to $13.4 million for the nine months ended March 31, 2014, a 16% decrease from $16.0 million in the year-ago period due to a 23%volume decline partially offset by a 8.4% higher price per BOE. Prices per BOE were $99.48 and $91.77, respectively, for the nine months ended March 31, 2014 and 2013.

Lease Operating Expenses (including ad valorem and production severance taxes). Lease operating expenses and production taxes for the nine months ended March 31, 2014 decreased $308,644, or 23%, to $1,008,409 compared to the corresponding year-ago period. Expenses were approximately $255,000 lower at the Giddings (due to fiscal 2013 dispositions partly offset by increased expense at GARP® wells) and approximately $50,000 lower at the Lopez field sold in December 2013.. Lease operating expense and production tax per barrel of oil equivalent was almost flat at $7.57 per BOE during year-ago period to $7.51 per BOE for the nine months ended March 31, 2014.

General and Administrative Expenses (“G&A”). G&A expenses, including $1.4 million of one-time charges, increased 30% to $6.9 million during the nine months ended March 31, 2014 from $5.3 million in the year-ago period. Excluding the one-time charges, G&A expenses increased $0.2 million reflecting $0.1 million of higher salaries and benefits, $0.2 million for bonus increases, and $0.1 million for lower overhead absorption to drilling projects, partially offset by $0.2 million of lower stock-based compensation expense.

The $1.4 million of one-time charges were related to the retirement of our Vice President and Chief Financial Officer during the current quarter and prior quarter expenses related to the exercise of 4.0 million incentive warrants and stock options. Together, these events resulted in additional expenses including $0.7 million of salaries and benefits, $.03 million of transaction fees, $0.1 million for executive search, $0.1 million of bonus and $0.2 million of stock compensation.

Stock-based compensation, including $0.2 million in non-recurring charges, was $1.1 million (17% of total G&A) for the nine months ended March 31, 2014 compared to $1.1 million (22% of total G&A) for the corresponding year-ago period

Restructuring Charges. The company recorded $1.3 million of restructuring expense in December 2013 primarily reflecting $0.9 million of termination benefits to be paid from January to December 2014 and $0.4 million of non-cash stock compensation expense for accelerated restricted stock vesting for terminated employees. See Note 13 — Restructuring.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased by 2.2% to $948,656 for the nine months ended March 31, 2014, compared to $928,342 for the corresponding year-ago period. This change was principally due to a 34% increase in depletion rate from $5.13 per BOE a year ago to $6.87 in the current nine-month period, partially offset by a 23% decline in volume as described above. Much of the higher depletion rate is due to higher future capital expenditures at Delhi associated with increased reserves reflected in our June 30, 2013 reserves report.

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 modest increases in certain oil field services and materials compared to the prior fiscal year. During fiscal 2014 to date, we have not seen material increases in costs. 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 reversion of our back-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, 2014.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended March 31, 2014, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2013 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, 2013.

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, natural gas liquids 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, 2014 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.

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, 2014 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 ITEM 1.

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 14 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2013 Annual Report. During the quarter ended March 31, 2014, there were no material developments in the status of those proceedings except as described below. 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

As previously reported, the Company and its wholly owned subsidiary are defendants in a lawsuit brought by John C. McCarthy et. al (the “plaintiffs”) in the Fifth District Court of Richland Parish, Louisiana in July 2011. The 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. On March 29, 2012, the Fifth District Court dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiff’s claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. The plaintiffs are seeking cancellation of the lease and monetary damages. We subsequently filed a second motion pleading “no cause of action,” with which the district court again agreed and dismissed the plaintiffs’ case on September 23, 2013. Plaintiffs again filed an appeal in November 2013.

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On October 14, 2013, a settlement agreement was executed in the lawsuit filed by Frederick M. Garcia and Lydia Garcia, et. al and the lawsuit was dismissed with prejudice on November 5, 2013. As previously reported, on July 26, 2012, we agreed to settle a lawsuit filed by Frederick M. Garcia and Lydia Garcia in December 2010 in Duval County, Texas, in which the plaintiffs alleged failure to maintain the lease beyond its primary term due to no production. Although we believed that the claims were without merit, we chose to settle for $67,000 in return for an extension of the primary term of the lease, an amount less than our expected cost to prevail in court through summary judgment.

As previously reported, on August 23, 2012, we, and our wholly owned subsidiary NGS Sub Corp and Robert S. Herlin, our President, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones (the “Jones lawsuit”) in the Western District Court of the Monroe Division, Louisiana. The plaintiffs allege primarily that we (defendants) wrongfully purchased the plaintiffs’ 0.048119 overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for EOR. We believe that the claims are without merit and are not timely, and we are vigorously defending against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the defendants to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the Plaintiff’s claims were valid on their face. On September 25, 2013, plaintiff Jones filed a Motion to Alter or Amend the September 17, 2013 judgment. The plaintiffs are seeking rescission of the assignment of the overriding royalty interest and monetary damages. On December 27, 2013, the court denied said Plaintiffs’ Motion, and on January 21, 2014 we filed a motion to reconsider the nondismissal of the remaining claims. Counsel has advised us that, based on information developed to date, the risk of loss in this matter is remote.

On December 13, 2013, we and our wholly owned subsidiaries Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging numerous breaches of certain 2006 agreements between the parties regarding the Delhi Field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined Area of Mutual Interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims.

On December 3, 2013, our wholly owned subsidiary NGS Sub. Corp. was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks, a resident of Louisiana, alleging that a former subsidiary of NGS Sub. Corp. improperly disposed of off lease water in a well located on the plaintiff’s land in Winn Parish in 2006. The plaintiff is requesting monetary damages and other relief. NGS Sub. Corp. disposed of the property in question along with its ownership of the subsidiary in 2008 to a third party. We have denied the claims.

ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 2013 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, 2013.

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

During the quarter ended March 31, 2014, the Company did not sell any equity securities that were not registered under the Securities Act.

During the quarter ended March 31, 2014, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and exercises of stock options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting.

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

January 1, 2014 to January 31, 2014	17,362 shares of Common Stock	$	12.34	Not applicable	Not applicable
February 1, 2014 to February 28, 2014	9,761 shares of Common Stock	$	12.83	Not applicable	Not applicable
March 1, 2014 to March 31, 2014	9,440shares of Common Stock	$	12.97	Not applicable	Not applicable

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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

A. Exhibits

4.1		Registration Rights Agreement, dated February 10, 2014, by and among Evolution Petroleum Corporation and certain investors named on the signature page thereto (incorporated by reference to Evolution Petroleum Corporation’s Registration Statement on Form S-3 filed on February 11, 2014).

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 to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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/ RANDALL D. KEYS
		Randall D. Keys
		Senior Vice President, Chief Financial Officer and Treasurer
		Principal Financial Officer and
		Principal Accounting Officer

Date: May 12, 2014