10-Q 1 a14-3961_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

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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 December 31, 2013

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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

2500 CityWest Blvd., Suite 1300, Houston, Texas 77042

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

Not Applicable

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: x No: o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: x No: o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o |  | Accelerated filer x
Non-accelerated filer o |  | Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o No: x

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of January 31, 2014, was 32,394,999.

Table of Contents

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 December 31, 2013 and June 30, 2013 | 2
| Unaudited Consolidated Condensed Statements of Operations for the three months ended December 31, 2013 and 2012 and for the six months ended December 31, 2013 and 2012 | 3
| Unaudited Consolidated Condensed Statements of Cash Flows for the six months ended December 31, 2013 and 2012 | 4
| Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the six months ended December 31, 2013 | 6
| Unaudited Notes to Consolidated Condensed Financial Statements | 7
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 16
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 25
ITEM 4. | CONTROLS AND PROCEDURES | 25
PART II. OTHER INFORMATION | 25
ITEM 1. | LEGAL PROCEEDINGS | 25
ITEM 1A. | RISK FACTORS | 26
ITEM 2. | UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS | 27
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES | 28
ITEM 4. | MINE SAFETY DISCLOSURES | 28
ITEM 5. | OTHER INFORMATION | 28
ITEM 6. | EXHIBITS | 28
SIGNATURES |  | 29

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PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)

|  | December 31, |  | June 30, |
|  | 2013 |  | 2013 |
Assets |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents |  | $ | 25,542,782 |  | $ | 24,928,585 |
Certificate of deposit |  | — |  | 250,000 |
Receivables |  |  |  |  |
Oil and natural gas sales |  | 1,497,561 |  | 1,632,853 |
Income taxes |  | 281,970 |  | 281,970 |
Joint interest partner |  | 2,368 |  | 49,063 |
Other |  | 12,088 |  | 918 |
Deferred tax asset |  | 26,133 |  | 26,133 |
Prepaid expenses and other current assets |  | 633,980 |  | 266,554 |
Total current assets |  | 27,996,882 |  | 27,436,076 |
Property and equipment, net of depreciation, depletion, and amortization Oil and natural gas properties — full-cost method of accounting, of which $4,258,459 and $4,112,704 at December 31, 2013 and June 30, 2013, respectively, were excluded from amortization |  | 38,244,071 |  | 38,789,032 |
Other property and equipment |  | 48,182 |  | 52,217 |
Total property and equipment |  | 38,292,253 |  | 38,841,249 |
Advances to joint interest operating partner |  | 43,646 |  | 26,059 |
Other assets |  | 235,972 |  | 252,912 |
Total assets |  | $ | 66,568,753 |  | $ | 66,556,296 |
Liabilities and Stockholders’ Equity |  |  |  |  |
Current liabilities |  |  |  |  |
Accounts payable |  | $ | 325,294 |  | $ | 642,018 |
Due to joint interest partner |  | 86,289 |  | 127,081 |
Accrued compensation |  | 743,804 |  | 1,385,494 |
Accrued restructuring charges |  | 955,821 |  | — |
Royalties payable |  | 139,553 |  | 91,427 |
Income taxes payable |  | — |  | 233,548 |
Other current liabilities |  | 537,114 |  | 153,182 |
Total current liabilities |  | 2,787,875 |  | 2,632,750 |
Long term liabilities |  |  |  |  |
Deferred income taxes |  | 8,748,636 |  | 8,418,969 |
Asset retirement obligations |  | 156,756 |  | 615,551 |
Deferred rent |  | 44,293 |  | 52,865 |
Total liabilities |  | 11,737,560 |  | 11,720,135 |
Commitments and contingencies (Note 11) |  |  |  |  |
Stockholders’ equity |  |  |  |  |
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at December 31, 2013, 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 32,062,186 shares at December 31, 2013, and 29,410,858 at June 30, 2013; outstanding 32,062,186 shares and 28,608,969 shares as of December 31, 2013 and June 30, 2013, respectively |  | 32,062 |  | 29,410 |
Additional paid-in capital |  | 33,264,497 |  | 31,813,239 |
Retained earnings |  | 21,534,317 |  | 24,013,035 |
|  | 54,831,193 |  | 55,856,001 |
Treasury stock, at cost, no shares and 801,889 shares as of December 31, 2013 and June 30, 2013, respectively |  | — |  | (1,019,840 | )
Total stockholders’ equity |  | 54,831,193 |  | 54,836,161 |
Total liabilities and stockholders’ equity |  | $ | 66,568,753 |  | $ | 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 |  | Six Months Ended |
|  | December 31, |  | December 31, |
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Revenues |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 4,344,765 |  | $ | 5,379,399 |  | $ | 8,936,142 |  | $ | 9,384,821 |
Natural gas liquids |  | 25,956 |  | 86,556 |  | 50,102 |  | 206,167 |
Natural gas |  | 21,568 |  | 182,103 |  | 39,744 |  | 348,616 |
Total revenues |  | 4,392,289 |  | 5,648,058 |  | 9,025,988 |  | 9,939,604 |
Operating Costs |  |  |  |  |  |  |  |  |
Lease operating expenses |  | 223,498 |  | 419,328 |  | 633,345 |  | 735,497 |
Production taxes |  | 13,032 |  | 20,863 |  | 21,435 |  | 42,236 |
Depreciation, depletion and amortization |  | 327,168 |  | 350,119 |  | 636,841 |  | 647,036 |
Accretion of discount on asset retirement obligations |  | 12,418 |  | 17,751 |  | 25,346 |  | 38,858 |
General and administrative expenses * |  | 2,642,082 |  | 1,815,276 |  | 4,571,033 |  | 3,520,700 |
Restructuring charges** |  | 1,332,186 |  | — |  | 1,332,186 |  | — |
Total operating costs |  | 4,550,384 |  | 2,623,337 |  | 7,220,186 |  | 4,984,327 |
Income (loss) from operations |  | (158,095 | ) | 3,024,721 |  | 1,805,802 |  | 4,955,277 |
Other |  |  |  |  |  |  |  |  |
Interest income |  | 7,701 |  | 5,614 |  | 15,404 |  | 11,230 |
Interest (expense) |  | (16,582 | ) | (16,564 | ) | (33,095 | ) | (32,992 | )
|  | (8,881 | ) | (10,950 | ) | (17,691 | ) | (21,762 | )
Income (loss) before income taxes |  | (166,976 | ) | 3,013,771 |  | 1,788,111 |  | 4,933,515 |
Income tax provision |  | 241,907 |  | 1,054,499 |  | 724,543 |  | 1,814,717 |
Net Income (Loss) |  | $ | (408,883 | ) | $ | 1,959,272 |  | $ | 1,063,568 |  | $ | 3,118,798 |
Dividends on Preferred Stock |  | 168,576 |  | 168,576 |  | 337,151 |  | 337,151 |
Net income (loss) available to common shareholders |  | $ | (577,459 | ) | $ | 1,790,696 |  | $ | 726,417 |  | $ | 2,781,647 |
Basic |  | $ | (0.02 | ) | $ | 0.06 |  | $ | 0.03 |  | $ | 0.10 |
Diluted |  | $ | (0.02 | ) | $ | 0.06 |  | $ | 0.02 |  | $ |  | 0.09 |
Weighted average number of common shares |  |  |  |  |  |  |  |  |
Basic |  | 30,063,676 |  | 28,071,317 |  | 29,335,498 |  | 28,032,223 |
Diluted |  | 30,063,676 |  | 31,856,417 |  | 32,377,918 |  | 31,836,983 |

* General and administrative expenses for the three months ended December 31, 2013 and 2012 included non-cash stock-based compensation expense of $316,422 and $393,579, respectively. For the corresponding six month period’s non-cash stock-based compensation expense was $689,860 and $747,369, respectively.

** Restructuring charges for the three months and six months ended December 31, 2013 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)

|  | Six Months Ended December 31, |
|  | 2013 |  | 2012 |
Cash flows from operating activities |  |  |  |  |
Net Income |  | $ | 1,063,568 |  | $ | 3,118,798 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Depreciation, depletion and amortization |  | 657,265 |  | 667,461 |
Stock-based compensation |  | 689,860 |  | 747,369 |
Stock-based compensation related to restructuring |  | 376,365 |  | — |
Accretion of discount on asset retirement obligations |  | 25,346 |  | 38,858 |
Settlements of asset retirement obligations |  | (57,247 | ) | (47,026 | )
Deferred income taxes |  | 329,667 |  | 1,498,760 |
Deferred rent |  | (8,574 | ) | (8,574 | )
Changes in operating assets and liabilities: |  |  |  |  |
Receivables from oil and natural gas sales |  | 135,292 |  | (797,933 | )
Receivables from income taxes and other |  | (11,170 | ) | (116 | )
Due to/from joint interest partner |  | 4,687 |  | 40,050 |
Prepaid expenses and other current assets |  | (367,426 | ) | 48,591 |
Accounts payable and accrued expenses |  | 174,842 |  | (390,979 | )
Royalties payable |  | 48,126 |  | (74,876 | )
Income taxes payable |  | (233,548 | ) | 115,801 |
Net cash provided by operating activities |  | 2,827,053 |  | 4,956,184 |
Cash flows from investing activities |  |  |  |  |
Proceeds from asset sales |  | 544,442 |  | 3,054,976 |
Capital expenditures for oil and natural gas properties |  | (856,943 | ) | (4,013,430 | )
Capital expenditures for other property and equipment |  | (9,637 | ) | — |
Other assets |  | (5,957 | ) | (26,110 | )
Net cash used in investing activities |  | (328,095 | ) | (984,564 | )
Cash flows from financing activities |  |  |  |  |
Proceeds on exercise of incentive stock options |  | 2,141,500 |  | — |
Cash dividends to preferred stockholders |  | (337,151 | ) | (337,151 | )
Cash dividends to common stockholders |  | (3,205,135 | ) | — |
Purchases of treasury stock |  | (1,127,801 | ) | (16,968 | )
Windfall tax benefit |  | 386,976 |  | — |
Maturity of certificate of deposit |  | 250,000 |  | — |
Recovery of short swing profits |  | 6,850 |  | — |
Deferred loan costs |  | — |  | (16,211 | )
Net cash used in financing activities |  | (1,884,761 | ) | (370,330 | )
Net increase in cash and cash equivalents |  | 614,197 |  | 3,601,290 |
Cash and cash equivalents, beginning of period |  | 24,928,585 |  | 14,428,548 |
Cash and cash equivalents, end of period |  | $ | 25,542,782 |  | $ | 18,029,838 |

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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 six months ended December 31, 2013 and 2012 are as follows:

|  | Six Months Ended |
|  | December 31, |
|  | 2013 |  | 2012 |
Income taxes paid |  | $ | 755,564 |  | $ | 200,156 |
Non-cash transactions: |  |  |  |  |
Change in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties |  | (225,062 | ) | 31,885 |
Change in due to joint interest partner used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties |  | 1,216 |  | (435,833 | )
Oil and natural gas properties incurred through recognition of asset retirement obligations |  | 48,988 |  | 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 Six Months Ended December 31, 2013

(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* |  | — |  | — |  | — |  | — |  | 1,066,225 |  | — |  | — |  | 1,066,225 |
Exercise of stock options |  | — |  | — |  | 2,726,911 |  | 2,727 |  | 2,757,380 |  | — |  | — |  | 2,760,107 |
Exercise of stock warrants |  | — |  | — |  | 905,391 |  | 905 |  | (905 | ) | — |  | — |  | — |
Issuance of restricted stock |  | — |  | — |  | 16,476 |  | 16 |  | (16 | ) | — |  | — |  | — |
Forfeitures of restricted stock |  | — |  | — |  | (51,099 | ) | (51 | ) | 51 |  | — |  | — |  | — |
Purchases of treasury stock |  | — |  | — |  | (144,462 | ) | — |  | — |  | — |  | (1,746,407 | ) | (1,746,407 | )
Retirements of treasury stock |  | — |  | — |  | — |  | (945 | ) | (2,765,302 | ) | — |  | 2,766,247 |  | — |
Net income |  | — |  | — |  | — |  | — |  | — |  | 1,063,568 |  | — |  | 1,063,568 |
Common Stock cash dividends |  | — |  | — |  | — |  | — |  | — |  | (3,205,135 | ) | — |  | (3,205,135 | )
Preferred Stock cash dividends |  | — |  | — |  | — |  | — |  | — |  | (337,151 | ) | — |  | (337,151 | )
Windfall tax benefit |  | — |  | — |  | — |  | — |  | 386,975 |  | — |  | — |  | 386,975 |
Recovery of short swing profits |  | — |  | — |  | — |  | — |  | 6,850 |  | — |  | — |  | 6,850 |
Balance, December 31, 2013 |  | 317,319 |  | $ | 317 |  | 32,062,186 |  | $ | 32,062 |  | $ | 33,264,497 |  | $ | 21,534,317 |  | $ | — |  | $ | 54,831,193 |

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

See accompanying notes to consolidated condensed financial statements.

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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 exploitation, development and re-development of known oil and gas resources for the production of crude oil and natural gas, utilizing conventional, specialized and proprietary technology to increase production, ultimate recoveries, or both.

Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 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.

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Note 2 — Property and Equipment

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

|  | December 31, 2013 |  | June 30, 2013 |
Oil and natural gas properties |  |  |  |  |
Property costs subject to amortization |  | $ | 42,746,486 |  | $ | 42,772,184 |
Less: Accumulated depreciation, depletion, and amortization |  | (8,760,874 | ) | (8,095,856 | )
Unproved properties not subject to amortization |  | 4,258,459 |  | 4,112,704 |
Oil and natural gas properties, net |  | $ | 38,244,071 |  | $ | 38,789,032 |
Other property and equipment |  |  |  |  |
Furniture, fixtures and office equipment, at cost |  | 332,151 |  | 322,514 |
Less: Accumulated depreciation |  | (283,969 | ) | (270,297 | )
Other property and equipment, net |  | $ | 48,182 |  | $ | 52,217 |

Unproved property not subject to amortization consists of unevaluated acreage of $4.2 million and $4.1 million as of December 31, 2013 and June 30, 2013, respectively, for our properties in the Mississippi Lime in Oklahoma. Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis. During the six months ended December 31, 2013 and the corresponding 2012 period, no impairments have been recorded.

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 December 31, 2013 and June 30, 2013 balance sheets by the items below.

|  | December 31, 2013 |  | June 30, 2013 |
Advances to joint interest operating partner |  | $ | 43,646 |  | $ | 26,059 |
Due to joint interest partner |  | 86,289 |  | 127,081 |

Note 4 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following are reconciliations of the beginning and ending asset retirement obligation balances:

|  | December 31, 2013 |  | 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 |  | (53,295 | ) | (51,086 | )
Accretion of discount |  | 25,346 |  | 72,312 |
Revision of previous estimates |  | 48,988 |  | 5,432 |
Asset retirement obligations due within one year included in “Other current liabilities” |  | (431,561 | ) | — |
Asset retirement obligations — end of period |  | $ | 156,756 |  | $ | 615,551 |

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Note 5 — Stockholders’ Equity

Common Stock

During the six months ended December 31, 2013 we issued (i) 1,008,657 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $2.1 million, and (ii) 2,622,723 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 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 $4.2 million, due to $1.1 million of stock compensation amortization ($0.4 million of which in the restructuring charge), $2.8 million from the exercise of stock options and warrants listed in (i) and (ii) above, and $0.4 million from tax benefits associated with stock compensation (i.e. windfall tax benefit).

Additional paid-in capital decreased by $2.8 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 144,462 shares of Treasury Stock from employees and directors at a cost of $12.09 per share or $1.7 million. 93,506 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 946,351 shares.

In December 2013 retained earnings were reduced by the $3.2 million of cash dividends we made to our common shareholders as the result of a common stock dividend policy approved by the Board of Directors in November 2013. 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 December 2013 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 December 31, 2013, 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 six months ended December 31, 2013 we paid $337,151 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 the six months ended December 31, 2013 will be treated for tax purposes as a return of capital and not as dividend income to the shareholder.

Note 6 — Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”). Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan. The 2004 Stock Plan authorized the issuance of 6,500,000 shares of common stock. No further shares are available for grant under the 2003 Stock Plan and 784,438 shares remain available for grant under the 2004 Stock Plan as of December 31, 2013.

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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 six months ended December 31, 2013 and 2012, stock-based compensation expense was $- 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.

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2013, and the changes during the fiscal year:

|  | Number of Stock Options and Incentive Warrants |  | Weighted Average Exercise Price |  | Aggregate Intrinsic Value (1) |  | Weighted Average Remaining Contractual Term (in years) |
Stock Options and Incentive Warrants outstanding at July 1, 2013 |  | 4,822,820 |  | $ | 1.99 |  |  |  |  |
Exercised |  | (4,069,815 | ) | $ | 1.99 |  |  |  |  |
Stock Options and Incentive Warrants outstanding at December 31, 2013 |  | 753,005 |  | $ | 2.01 |  | $ | 7,778,744 |  | 2.0 |
Vested or expected to vest at December 31, 2013 |  | 753,005 |  | $ | 2.01 |  | $ | 7,778,744 |  | 2.0 |
Exercisable at December 31, 2013 |  | 753,005 |  | $ | 2.01 |  | $ | 7,778,744 |  | 2.0 |

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($12.34 as of December 31, 2013) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 4,069,815 Stock Options and Warrants exercised during the six months ended December 31, 2013 with an aggregate intrinsic value of $41,247,805.

During the six months ended December 31, 2012 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 December 31, 2013 and 2012 was $316,422 and $393,579, respectively. For the six months ended December 31, 2013 and 2012, such compensation expense was $689,860 and $747,369, respectively. See Note 12 — Restructuring, for stock compensation included in Restructuring Charge for the six months ended December 31, 2013.

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

|  | Number of Restricted Shares |  | Weighted Average Grant-Date Fair Value |
Unvested at July 1, 2013 |  | 386,599 |  | $ | 6.65 |
Granted |  | 16,476 |  | 12.14 |
Vested |  | (142,404 | ) | $ | 6.21 |
Forfeited |  | (9,066 | ) | $ | 5.98 |
Unvested at December 31, 2013 |  | 251,605 |  | $ | 7.28 |

At December 31, 2013, unrecognized stock compensation expense related to Restricted Stock grants totaled $1,359,862. Such unrecognized expense will be recognized over a weighted average period of 1.8 years.

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Note 7 — Fair Value Measurement

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

The three levels are defined as follows:

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

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

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

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

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

Note 8 — Income Taxes

We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

There were no FIN 48 unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the six months ended December 31, 2013. 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, 2012.

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 six months ended December 31, 2013 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 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

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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 December 31, 2013 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 $724,543 and $1,814,717 for the six months ended December 31, 2013 and 2012, respectively, with corresponding effective rates of 41% and 37%.

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Note 9 — Net Income Per Share

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

|  | Three Months Ended December 31, |  | Six Months Ended December 31, |
|  | 2013 |  | 2012 |  | 2013 |  | 2012 |
Numerator |  |  |  |  |  |  |  |  |
Net income available to common shareholders |  | $ | (577,459 | ) | $ | 1,790,696 |  | $ | 726,417 |  | $ | 2,781,647 |
Denominator |  |  |  |  |  |  |  |  |
Weighted average number of common shares — Basic |  | 30,063,676 |  | 28,071,317 |  | 29,335,498 |  | 28,032,223 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |
Common stock warrants issued in connection with equity and financing transactions |  | — |  | 839 |  | — |  | 845 |
Stock Options and Incentive Warrants |  | — |  | 3,784,261 |  | 3,042,420 |  | 3,803,915 |
Total weighted average dilutive securities |  | — |  | 3,785,100 |  | 3,042,420 |  | 3,804,760 |
Weighted average number of common shares and dilutive potential common shares used in diluted EPS |  | 30,063,676 |  | 31,856,417 |  | 32,377,918 |  | 31,836,983 |
Net income per common share — Basic |  | $ | (0.02 | ) | $ | 0.06 |  | $ | 0.03 |  | $ | 0.10 |
Net income per common share — Diluted |  | $ | (0.02 | ) | $ | 0.06 |  | $ | 0.02 |  | $ | 0.09 |

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

Outstanding Potential Dilutive Securities |  | Weighted Average Exercise Price |  | Outstanding at December 31, 2013 |
Common stock warrants issued in connection with equity and financing transactions |  | $ | — |  | — |
Stock Options and Incentive Warrants |  | $ | 2.01 |  | 753,005 |
Total |  | $ | 2.01 |  | 753,005 |

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

Outstanding Potential Dilutive Securities |  | Weighted Average Exercise Price |  | Outstanding at December 31, 2012 |
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 10 - Unsecured Revolving Credit Agreement

On February 29, 2012, Evolution Petroleum Corporation entered into a Credit Agreement (the “Credit Agreement”) with Texas Capital Bank, N.A. (the “Lender”). The Credit Agreement provides 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.

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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 December 31, 2013, 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, and we were in compliance with all the covenants of the Credit Agreement.

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.

Note 11 — Commitments and Contingencies

We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdiction in which we operate. 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 August 1, 2016. Future minimum lease commitments as of December 31, 2013 under this operating lease are as follows:

For the twelve months ended December 31, |  |  |
2014 |  | $ | 159,011 |
2015 |  | 159,011 |
2016 |  | 92,756 |
Total |  | $ | 410,778 |

Rent expense for the three months ended December 31, 2013 and 2012 was $44,759 and $36,808, respectively. For the corresponding six month periods of 2013 and 2012 rent expense was $86,667 and $73,617, respectively.

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Employment Contracts. We have employment agreements with our three 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 December 31, 2013 is approximately $692,000.

In connection with Sterling McDonald’s retirement announced in January 2014, we expect to pay Mr. McDonald a severance of $478,000 representing his base salary and anticipated bonus under our Cash Incentive Plan and $70,000 in other benefits. In addition, we will accelerate the vesting of Mr. McDonald’s previously unvested restricted stock awards which will result in $220,500 of stock compensation expense to us.

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.

Note 12 — Restructuring

On November 1, 2013, we undertook an initiative refocusing our business on GARP® development that resulted in adjustment of our workforce towards less emphasis on engineering and greater emphasis on sales and marketing. Accordingly, we accrued a restructuring charge in the second quarter ended December 31, 2013, based on agreements with terminated employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for non-compete clauses, incurring pre-tax cash and non-cash charges of approximately $1,332,000, of which $376,000 are non-cash charges related to accelerated stock compensation expenses. Our current estimates of accounting charges related to the initiative as of December 31, 2013 are as follows:

Type of Cost |  | December 31, 2013 |
Salary Expense |  | $ | 616,000 |
Cash Incentive Plan |  | 186,000 |
Stock Compensation Expense |  | 376,000 |
Other Benefits |  | 154,000 |
Total Restructuring Charges |  | $ | 1,332,000 |

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.

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Executive Overview

General

We are engaged primarily in the exploitation, development and re-development of known oil and gas resources for the production of crude oil and natural gas, utilizing conventional, specialized and proprietary technology to increase production, ultimate recoveries, or both.

We are focused on increasing underlying net asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including 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 generate scalable, low unit cost, development and re-development opportunities that minimize exploration risks. These opportunities involve the application of modern technology, our own patented artificial lift technology using the trade name of GARP®, and our specific expertise in overlooked areas of the United States.

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

· Enhanced Oil Recovery (EOR), and

· Bypassed Primary Resources

We expect to fund 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 Second Quarter Fiscal 2014 and Project Update

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

“Q1-14” & “prior quarter” is the three months ended September 30, 2013, the company’s 1 st quarter of fiscal 2014.

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

Operations

· For Q2-14, the Company incurred a net loss of $0.6 million due to $2.1 million of one-time charges, compared to net income of $1.3 million in the prior quarter and $1.8 million in the year-ago quarter. The current quarter’s loss was due to a pre-tax $1.3 million restructuring charge, a $0.8 million non-recurring charge associated with the restructuring and stock option exercises, higher G&A expense, a higher income tax expense, and lower revenues, partially offset by reduced LOE.

· Current quarter revenue decreased 5% sequentially to $4.4 million from $4.6 million in the prior quarter and decreased 22% from $5.6 million in the year-ago quarter. The sequential decline was due to lower Delhi crude oil prices offset by higher sales volumes from Delhi and from GARP® wells. The decrease from the year-ago quarter is primarily due to lower Delhi revenue driven by both lower volumes and prices, as well as the absence of Giddings properties that were divested in late December 2012, offset by the addition of GARP® production.

· Black oil volumes accounted for 96% of total volumes and 99% of revenues during Q2-14, compared sequentially to 96% of volume and 99% of revenues in the prior quarter, while the year-ago quarter’s oil volume was 82% of volume and 95% of revenue. Delhi oil volumes increased 6% from the prior quarter and decreased 9% compared to the year-ago quarter. The sequential increase in current quarter Delhi production reflects resumption of CO 2 injection that had been previously curtailed due to the previously disclosed June 2013 environmental event.

· The blended oil, NGL and natural gas product price we received in Q2-14 decreased 12% sequentially to $93.66 per BOE from $106.17 in the prior quarter, and increased 6% from $88.23 in the year-ago quarter. Current quarter oil prices decreased 12% sequentially to $96.70 and decreased 6% 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, although the price spread to WTI narrowed to 2% compared to the 10-20% premium experienced in prior periods. The LLS price premium in January 2014 has increased back to the ~10% level. NGL price was flat sequentially and decreased 16% from the year-ago quarter to $30.64, while natural gas price increased 9% sequentially to $3.21 and was flat compared to the year-ago quarter.

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Projects — Core Assets

Delhi EOR Project

· Production in our Delhi enhanced oil recovery project increased 6% sequentially and decreased 9% from the year-ago quarter to 464 BOPD net to our 7.4% royalty interest (6,264 gross BOPD). The sequential increase was due in part to resumption of CO 2 injection in a portion of the field following the essential completion of the previously disclosed remediation of a fluids release in the field beginning in June 2013. The decrease over the prior year is due to field response to development expenditures during 2012 that more than offset the effects of the temporary production impact of the remediation work during the second half of calendar 2013. The operator had temporarily suspended CO 2 injection in the area surrounding the discovered fluid release in order to re-enter the previously plugged well(s) believed to be the source of the fluid release. The reduction in CO 2 injection that “drives” tertiary production temporarily reduced oil production in the area affected by the fluids release.

The temporary decline in production combined with the remediation expense, net of any insurance reimbursements, is expected to delay the reversion of our 24% working interest to later in 2014, excluding the effect of any indemnity of us by the operator. To date, the operator has not agreed to the application of the indemnity and their 2006 assumption of environmental liabilities, and 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 litigation asserts various breaches of the 2006 purchase and sale agreement between us and the operator including charging our payout account for the cost of their remediation work, failure to timely assign us our reversionary working interest due to unallowed charges to the deemed payout account, failure to indemnify us for reductions in production due to the environmental event in June 2013, charging our payout account $41.7 million through December 31, 2013 for the cost of the processing plant as an operating cost and not a capital cost, over $2.4 million of plugging and abandonment cost through December 31, 2013 charged as operating expense and not as capital, and failure to honor acquisitions made by the operator within the area of mutual interest.

Our working interest reversion, when it occurs as projected sometime in calendar 2014, will more than triple our revenue interest to more than 26.5%, while our cost bearing interest will increase from 0% to 23.9%.

· Realized oil prices at Delhi decreased 12% sequentially and decreased 7% from the year-ago quarter to $97 per BO. Realized prices were $110 per BO in the previous quarter and $104 per BO in the year-ago quarter.

· The operator has stated its intention to install a plant to recover methane and natural gas liquids from the recycle gas stream, targeting installation for some time in calendar 2015, an earlier date than projected in our June 30, 2013 reserve report. The operator has further stated its intention to delay significant further capital expenditures until our reversion has occurred. 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)

· Subsequent to the end of the quarter, we entered into an agreement 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 the operator will provide the wells, leases and most required tangible 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.

· Our current commercial GARP® in stallations continue to perform as expected.

Projects — Non-Core Assets

Mississippi Lime

· We undertook the recompletion of the Sneath well to plug 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. Production testing is underway. Unless we achieve more encouraging results, we do not currently contemplate further development of our leasehold this fiscal year.

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Lopez Field (South Texas) — Sold in December 2013

· Effective December 1, 2013, we completed the sale of our producing assets and our undeveloped reserves in the Lopez Field. Had the divestment been completed at the beginning of the quarter, our production would have been reduced 7.0 BOE per day with approximately $57,000 of revenue, $22,000 of direct well expense (using the company’s average $6.80/BOE depletion rate) and $25,000 of pre-tax well income ($39/BOE) would have been absent in the current quarter’s results. Similarly, if the divestment had been completed July 1, 2013, approximately $117,000 of revenue, $189,000 of direct well expense (reflecting the company’s average $6.86/BOE depletion rate) and $72,000 of pre-tax well loss ($58/BOE) would have been absent from our results for the six months ended December 31, 2013.

Restructuring

On November 1, 2013, we undertook an initiative refocusing our operating resources on growing our Delhi Field EOR project, commercialization of our GARP® patented artificial lift technology and directly rewarding our common shareholders with continuing cash distributions. Results during the current quarter include:

· Reduced our workforce by 27%, leading to a $1,332,000 pre-tax restructuring charge. The charge includes 12 monthly installments of salary and benefit continuation, and immediate accelerated vesting of equity awards, for terminated employees in exchange for non-compete clauses. Of the charge, $376,000 was non-cash expense related to accelerated stock compensation vesting.

· Recorded $0.8 million of one-time pre-tax charges arising from the exercises of 4 million of 4.8 million options, providing us $2.1 million of cash proceeds. The exercises were a reaction to our new dividend policy. The charges included a 1% banking fee to orderly move 2.2 million exercised shares through the market to fund withholding tax liabilities and exercise costs, pay our $383,000 share of payroll tax liabilities associated thereto, and $168,000 in recruiting fees to replace Mr. McDonald.

· Going forward, approximately $1.4 million in recurring G&A expense will be reduced. The adjustment of our workforce and one member reduction to our Board, will allow us to place greater emphasis on sales and marketing functions necessary for the full commercialization of GARP®.

· We began directly rewarding our common shareholders with a new dividend policy. Our Board approved our first-ever cash dividend to common shareholders in the amount of $0.10 per share, payable December 27, 2013 to shareholders of record as of December 6, 2013, with the intention of further regular distributions consistent with expected improving cash flows at Delhi.

· Stock option exercises raised $2.1 million in cash proceeds, and will create approximately $10.6 million of future equity and permanent federal income tax savings on the next $31.2 million of otherwise taxable income at a 34% tax rate. This “windfall tax benefit” temporarily displaces the percentage depletion in excess of basis deduction that has recently been lowering our book tax rate. On a financial reporting basis, the “windfall tax benefit” will be recorded as a reduction in current income taxes payable each year and increase equity, to the extent cash taxes otherwise payable are reduced to zero. Accordingly, our book tax rate has temporarily risen, since the “windfall” doesn’t run through the income statement under GAAP.

· Dividends distributions to preferred and common shareholders will be characterized as return of capital and not taxable dividends for the six months ended December 31, 2013. The Option Deductions have driven our tax earnings and profits account into deficit, making cash dividends a return of capital to the receiving shareholder.

See a full discussion in “Note 8 — Income Taxes” to our financial statements.

Looking Forward

· ~$0.7 million of cash proceeds from the exercise of ISO’s will be recorded in FQ3-14. In January, Mr. McDonald cash exercised all 350,175 of his remaining ISO’s.

· There will be a ~$0.7 million one-time pretax charge to earnings in the quarter ending March 31, 2014. As previously reported, Mr. McDonald will be provided that same benefits as the terminated employees.

· Long-term incentive awards normally paid in stock will be accrued as a cash “stay bonus” in this fiscal year. Due to the restructure, the Board replaced the current year’s annual LTIP award payable in stock vesting over four years, with a “stay bonus” award for retained employees equal to one-fourth of the normal LTIP amount. This will cause further reductions to stock-based compensation, with an offsetting increase in accrued bonus expense.

· 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 December 31, 2013, our working capital was $25.2 million, compared to working capital of $24.8 million at June 30, 2013. The $0.4 million increase in working capital since June 30, 2013 was due primarily to $0.6 million of increased cash, together with $0.4 of increased tax deposits, partially offset by decreased accounts receivable, and certificates of deposit partially offset by higher current liabilities.

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Cash Flows from Operating Activities

For the six months ended December 31, 2013, cash flows provided by operating activities were $2.8 million, reflecting $3.1 million provided by operations before $0.3 million was used by working capital. Of the $3.1 million provided before working capital changes, $1.1 million was due to net income, which reflects a $1.3 million restructuring charge, and $2.0 million was attributable to non-cash expenses.

For the six months ended December 31, 2012, cash flows provided by operating activities were $5.0 million, reflecting $6.0 million provided by operations before $1.0 million was used in working capital. Of the $6.0 million provided before working capital changes, $3.1 million was due to net income and $2.9 million was due primarily to non-cash expenses.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2013 was $0.9 million. Development activities were predominantly for GARP® installations in Giddings and additional testing in the Hendrickson well in the Mississippi Lime. We received approximately $544,000 of additional proceeds from asset sales, including $400,000 for the recent sales of our South Texas properties.

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2012 was $4.0 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.

Oil and gas capital expenditures incurred, but not yet paid, were $0.5 million and $3.6 million, respectively, for the six months ended December 31, 2013 and 2012. These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

Cash Flows from Financing Activities

In the six months ended December 31, 2013, we used $1.9 million in cash for financing activities, including cash inflows of $2.1 million from stock option exercise proceeds and $0.4 million of windfall tax benefits, which was more than offset by cash outflows of $3.2 million for common dividends, $0.3 million for preferred dividends and $1.1 million for treasury stock purchases related to incentive stock warrant and stock option exercises and restricted stock vestings.

In the six months ended December 31, 2012, we paid preferred dividends of $0.3 million, in addition to a minimal amount of treasury stock purchases and deferred loan costs.

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 $25.2 million of working capital on hand at December 31, 2013 and internally generated funds from operations. Our capital budget includes up to $17 million of development expenditures at Delhi, subject to the actual reversion date of our working interest and the rate at which calendar 2014 capital is expended there. Our GARP® business is expected to require approximately $1 million, depending upon expansion of the recent installation agreement and any other new agreement. No capital is currently allocated for further drilling in the Mississippian Lime assets.

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Results of Operations

Three month period ended December 31, 2013 and 2012

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

|  | Three Months Ended |  |  |  |  |
|  | December 31, |  |  |  | % |
|  | 2013 |  | 2012 |  | Variance |  | Change |
Sales Volumes, net to the Company: |  |  |  |  |  |  |  |  |
Crude oil (Bbl) |  | 44,930 |  | 52,270 |  | (7,340 | ) | (14.0 | )%
NGLs (Bbl) |  | 847 |  | 2,378 |  | (1,531 | ) | (64.4 | )%
Natural gas (Mcf) |  | 6,723 |  | 56,210 |  | (49,487 | ) | (88.0 | )%
Crude oil, NGLs and natural gas (BOE) |  | 46,898 |  | 64,016 |  | (17,118 | ) | (26.7 | )%
Revenue data: |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 4,344,765 |  | $ | 5,379,399 |  | $ | (1,034,634 | ) | (19.2 | )%
NGLs |  | 25,956 |  | 86,556 |  | (60,600 | ) | (70.0 | )%
Natural gas |  | 21,568 |  | 182,103 |  | (160,535 | ) | (88.2 | )%
Total revenues |  | $ | 4,392,289 |  | $ | 5,648,058 |  | $ | (1,255,769 | ) | (22.2 | )%
Average price: |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) |  | $ | 96.70 |  | $ | 102.92 |  | $ | (6.22 | ) | (6.0 | )%
NGLs (per Bbl) |  | 30.64 |  | 36.40 |  | (5.76 | ) | (15.8 | )%
Natural gas (per Mcf) |  | 3.21 |  | 3.24 |  | (0.03 | ) | (0.9 | )%
Crude oil, NGLs and natural gas (per BOE) |  | $ | 93.66 |  | $ | 88.23 |  | $ | 5.43 |  | 6.2 | %
Expenses (per BOE) |  |  |  |  |  |  |  |  |
Lease operating expense |  | $ | 4.77 |  | $ | 6.55 |  | $ | (1.78 | ) | (27.2 | )%
Production taxes |  | $ | 0.28 |  | $ | 0.33 |  | $ | (0.05 | ) | (15.2 | )%
Depletion expense on oil and natural gas properties (a) |  | $ | 6.80 |  | $ | 5.24 |  | $ | 1.56 |  | 29.8 | %

(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $8,222 and $14,462, for the three months ended December 31, 2013 and 2012, respectively.

Net Income (Loss) Available to Common Shareholders. For the three months ended December 31, 2013, we incurred a net loss of $577,459 or $0.02 per share, (which includes a pre-tax non-cash $1.3 million restructuring charge, $0.8 million of non-recurring charges related to the restructuring and stock option exercises, and $316,422 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,392,289. This compares to a net income of $1,790,696, or $0.06 per diluted share, (which includes $393,579 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $5,648,058 for the year-ago quarter. Increased revenues were offset by higher operating expenses and higher income tax, reflecting a higher effective tax rate. Additional details of the components of net income are explained in greater detail below.

Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended December 31, 2013 decreased 27% to 46,898 BOE’s compared to 64,016 BOE’s for the year-ago quarter. This 17,118 volume decrease primarily reflects lower Giddings Field volumes, impacted by properties sold in Fiscal 2013, together with a decrease in Delhi Field volumes. Our crude oil sales volumes for the current quarter include 42,673 from our interests in Delhi and 2,257 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 46,815 barrels from our interests in Delhi and 5,455 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the three months ended December 31, 2013 declined 64% to 847 barrels compared to 2,378 barrels in the year-ago-quarter. Current quarter natural gas volumes, virtually all produced at Giddings, decreased 88% to 6,723 mcf from 56,210 mcf in the year-ago quarter. At the end of the current quarter, virtually all of Giddings production had been divested, except for our GARP® wells.

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Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $1.3 million to $4.4 million for the current quarter, a 22% decrease from $5.6 million in the year-ago quarter due to a 27% volume decline, partially offset by a 6% higher price per BOE. Prices per BOE were $93.66 and $88.23, 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 $203,661, or 46%, to $236,530 compared to the year-ago quarter. Expenses were $41,000 lower at the Lopez Field, $44,000 lower at our Oklahoma properties, and declined $109,000 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 27% from $6.88 per BOE during year-ago quarter to $5.05 per BOE during current quarter.

General and Administrative Expenses (“G&A”). G&A expenses, including $0.8 million of one-time charges, increased 46% to $2.6 million during the three months ended December 31, 2013 from $1.8 million in the year-ago quarter. As a result of the exercise of 4.0 million incentive warrants and stock options during the current quarter, the Company incurred $251,000 of transactions fees and $383,500 additional payroll expense that impact respective variances below. The $0.8 million increase was due primarily to $455,000 in higher salaries and benefits, $96,000 in higher bonus expense, and $40,000 increased business development, $180,000 higher transaction fees and $115,000 of increased consulting expense partially offset by $77,000 of lower stock compensation and $63,000 of lower legal expense. Stock-based compensation was $316,422 (12% of total G&A) for the current quarter compared to $393,579 (22% of total G&A) for the year-ago quarter. Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Restructuring Charges. We booked $1.3 million of restructuring expense in the current quarter primarily reflecting $0.9 million of termination benefits to be paid from January to December 2014 and a $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased 6.6% to $327,168 for the three months ended December 31, 2013, compared to $350,119 for the year-ago quarter. This change was principally due to a 30% increase in depletion rate from $5.24 per BOE in the year-ago quarter to $6.80 in the current quarter partially offset by an 27% 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.

Six month period ended December 31, 2013 and 2012

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

|  | Six Months Ended December 31, |  |  |  | % |
|  | 2013 |  | 2012 |  | Variance |  | Change |
Sales Volumes, net to the Company: |  |  |  |  |  |  |  |  |
Crude oil (Bbl) |  | 86,745 |  | 91,352 |  | (4,607 | ) | (5.0 | )%
NGLs (Bbl) |  | 1,644 |  | 5,759 |  | (4,115 | ) | (71.5 | )%
Natural gas (Mcf) |  | 12,910 |  | 122,079 |  | (109,169 | ) | (89.4 | )%
Crude oil, NGLs and natural gas (BOE) |  | 90,541 |  | 117,457 |  | (26,916 | ) | (22.9 | )%
Revenue data: |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 8,936,142 |  | $ | 9,384,821 |  | $ | (448,679 | ) | (4.8 | )%
NGLs |  | 50,102 |  | 206,167 |  | (156,065 | ) | (75.7 | )%
Natural gas |  | 39,744 |  | 348,616 |  | (308,872 | ) | (88.6 | )%
Total revenues |  | $ | 9,025,988 |  | $ | 9,939,604 |  | $ | (913,616 | ) | (9.2 | )%
Average price: |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) |  | $ | 103.02 |  | $ | 102.73 |  | $ | 0.29 |  | 0.3 | %
NGLs (per Bbl) |  | 30.48 |  | 35.80 |  | (5.32 | ) | (14.9 | )%
Natural gas (per Mcf) |  | 3.08 |  | 2.86 |  | 0.22 |  | 7.7 | %
Crude oil, NGLs and natural gas (per BOE) |  | $ | 99.69 |  | $ | 84.62 |  | $ | 15.07 |  | 17.8 | %
Expenses (per BOE) |  |  |  |  |  |  |  |  |
Lease operating expenses |  | $ | 7.00 |  | $ | 6.26 |  | $ | 0.74 |  | 11.8 | %
Production taxes |  | $ | 0.24 |  | $ | 0.36 |  | $ | (0.12 | ) | (33.3 | )%
Depletion expense on oil and natural gas properties (a) |  | $ | 6.86 |  | $ | 5.28 |  | $ | 1.58 |  | 29.9 | %

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(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $16,143 and $26,711 for the six months ended December 31, 2013 and 2012, respectively.

Net Income Available to Common Shareholders. For the six months ended December 31, 2013, we generated net income of $726,417 or $0.02 per diluted share, (which includes a $1.3 million non-cash restructuring charge, $0.8 million of non-recurring charges related to the restructuring and stock option exercises and $689,860 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $9,025,988. This compares to a net income of $2,781,647, or $0.09 per diluted share, (which includes $747,369 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $9,939,604 for the corresponding year-ago period. The earnings decline is due to lower revenue and higher operating expense partially offset by lower 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 six months ended December 31, 2013 decreased 23% to 90,541 BOE’s compared to 117,457 BOE’s for the year-ago period. This 26,916 volume decrease primarily reflects the loss of production and sales volumes of properties sold in Fiscal 2013, partially offset by increases in Delhi Field volumes and GARP® wells. Our crude oil sales volumes for the six months ended December 31, 2013 include 82,952 from our interests in Delhi and 3,793 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the corresponding year-ago period included 81,268 barrels from our interests in Delhi and 10,084 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the six months ended December 31, 2013 declined 72% to 1,644 barrels compared to 5,759 barrels in the year-ago period. Current period natural gas volumes, virtually all produced at Giddings, decreased 89% to 12,910 mcf from 122,079 mcf for in the six months ended December 31, 2012.

Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $0.9 million to $9.0 million for the six months ended December 31, 2013, a 9% decrease from $9.9 million in the year-ago period due to a 23%volume decline partially offset by a 18% higher price per BOE. Prices per BOE were $99.69 and $84.62, respectively, for the six months ended December 31, 2013 and 2012.

Lease Operating Expenses (including ad valorem and production severance taxes). Lease operating expenses and production taxes for the six months ended December 31, 2013 decreased $122,953, or 16%, to $654,780 compared to the corresponding year-ago period. Expenses were $54,000 higher at the Lopez Field and $34,000 at our Oklahoma properties, but declined $190,000 in the Giddings Field due to divestitures of non-core properties during Fiscal 2013, partially offset by higher expenses at GARP® wells. Lease operating expense and production tax per barrel of oil equivalent increased 9% from $6.62 per BOE during year-ago period to $7.24 per BOE for the six months ended December 31, 2013.

General and Administrative Expenses (“G&A”). G&A expenses, including $0.8 million of one-time charges, increased 30% to $4.6 million during the six months ended December 31, 2013 from $3.5 million in the year-ago period. As a result of the recent exercise of 4.0 million incentive warrants and stock options, the Company incurred $251,000 of transactions fees and $383,500 additional payroll expense that impact respective variances below. The $1.1 million increase was due primarily to $627,000 in higher salaries and benefits, $168,000 of higher transaction fees, $126,000 in higher bonus expense, and $69,000 increased business development, and $72,000 of increased management consulting expense partially offset by $64,000 of lower legal expense and $57,000 decreased stock compensation expense. Stock-based compensation was $689,860 (15% of total G&A) for the six months ended December 31, 2013 compared to $747,369 (21% of total G&A) for the corresponding year-ago period. Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Restructuring Charges. The company booked $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 a $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees.

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Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased by 1.6% to $636,841 for the six months ended December 31, 2013, compared to $647,036 for the corresponding year-ago period. This change was principally due to a 30% increase in depletion rate from $5.28 per BOE a year ago to $6.86 in the current six-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, these input costs were generally unchanged compared to fiscal 2013. 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. See “Note 12 - Restructuring” within “ Item I. Financial Information.”

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 December 31, 2013.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended December 31, 2013, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 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 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 December 31, 2013 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 December 31, 2013 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 14 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2013 Annual Report. During the quarter ended December 31, 2013, 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

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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. 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 have again filed an appeal.

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 a portion of the claims were allowed for defendants. 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. On December 27, 2013, the court denied said Plaintiffs’ Motion, and on January 21, 2014 we filed a motion to reconsider. Counsel has advised us that on the 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 133 rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC 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 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.

On December 3, 2013, our wholly owned subsidiary NGS Sub. Corp. was served with a lawsuit filed in the 8 th 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. 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.

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

During the quarter ended December 31, 2013, the Company did not sell any equity securities that were not registered under the Securities Act.

During the quarter ended December 31, 2013, the Company received shares of common stock from employees and directors of the Company for the cashless exercise of stock options and warrants, and to pay their share of payroll taxes arising from vestings of restricted stock and exercises of stock options and warrants. 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 |
October 1, 2013 to October 31, 2013 |  | 99 shares of Common Stock |  | $ | 11.26 |  | Not applicable |  | Not applicable |
November 1, 2013 to November 30, 2013 |  | 55,234 shares of Common Stock |  | $ | 12.14 |  | Not applicable |  | Not applicable |
December 1, 2013 to December 31, 2013 |  | 78,907 shares of Common Stock |  | $ | 12.13 |  | 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.

ITE M 6. EXHIBITS

A. Exhibits

| 31.1 |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
| 31.2 |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
| 32.1 |  | Certification of Chief Executive Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.
| 32.2 |  | Certification of Chief Financial Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.
| 99.1 |  | Second Amendment to the Evolution Petroleum Corporation 2004 Amended and Restated Stock Plan
| 101.INS |  | XBRL Instance Document
| 101.SCH |  | XBRL Taxonomy Extension Schema Document
| 101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document
| 101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document
| 101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document
| 101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

EVOLUTION PETROLEUM CORPORATION

(Registrant)

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

Date: February 7, 2014

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