10-Q 1 a12-29462_110q.htm 10-Q

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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, 2012

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 February 4, 2013, was 28,106,796.

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, 2012 and June 30, 2012 | 2
| Unaudited Consolidated Condensed Statements of Operations for the three months ended December 31, 2012 and 2011 and for the six months ended December 31, 2012 and 2011 | 3
| Unaudited Consolidated Condensed Statements of Cash Flows for the six months ended December 31, 2012 and 2011 | 4
| Unaudited Notes to Consolidated Condensed Financial Statements | 5
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 12
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 19
ITEM 4. | CONTROLS AND PROCEDURES | 20
PART II. OTHER INFORMATION | 20
ITEM 1. | LEGAL PROCEEDINGS | 20
ITEM 1A. | RISK FACTORS | 20
ITEM 2. | UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS | 20
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES | 21
ITEM 4. | MINE SAFETY DISCLOSURES | 21
ITEM 5. | OTHER INFORMATION | 21
ITEM 6. | EXHIBITS | 21
SIGNATURES | 22

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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, |
|  | 2012 |  | 2012 |
Assets |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents |  | $ | 18,029,838 |  | $ | 14,428,548 |
Certificates of deposit |  | 250,000 |  | 250,000 |
Receivables |  |  |  |  |
Oil and natural gas sales |  | 2,141,280 |  | 1,343,347 |
Joint interest partner |  | 24,871 |  | 96,151 |
Income taxes |  | 92,885 |  | 92,885 |
Other |  | 306 |  | 190 |
Deferred tax asset |  | 162,746 |  | 325,235 |
Prepaid expenses and other current assets |  | 184,842 |  | 233,433 |
Total current assets |  | 20,886,768 |  | 16,769,789 |
Property and equipment, net of depreciation, depletion, and amortization |  |  |  |  |
Oil and natural gas properties — full-cost method of accounting, of which $9,031,522 and $6,042,094 at December 31, 2012 and June 30, 2012, respectively, were excluded from amortization |  | 40,276,684 |  | 40,476,172 |
Other property and equipment |  | 68,031 |  | 92,271 |
Total property and equipment |  | 40,344,715 |  | 40,568,443 |
Advances to joint interest operating partner |  | — |  | 1,366,921 |
Other assets |  | 269,758 |  | 250,333 |
Total assets |  | $ | 61,501,241 |  | $ | 58,955,486 |
Liabilities and Stockholders’ Equity |  |  |  |  |
Current liabilities |  |  |  |  |
Accounts payable |  | $ | 415,489 |  | $ | 407,570 |
Due joint interest partner |  | 1,383,991 |  | 3,217,975 |
Accrued compensation |  | 609,350 |  | 1,005,624 |
Royalties payable |  | 219,137 |  | 294,013 |
Income taxes payable |  | 137,924 |  | 91,967 |
Other current liabilities |  | 170,873 |  | 71,768 |
Total current liabilities |  | 2,936,764 |  | 5,088,917 |
Long term liabilities |  |  |  |  |
Deferred income taxes |  | 7,541,364 |  | 6,205,093 |
Asset retirement obligations |  | 826,840 |  | 968,677 |
Deferred rent |  | 61,437 |  | 70,011 |
Total liabilities |  | 11,366,405 |  | 12,332,698 |
Commitments and contingencies (Note 11) |  |  |  |  |
Stockholders’ equity |  |  |  |  |
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at December 31, 2012, and June 30, 2012 with a liquidation preference of $25.00 per share |  | 317 |  | 317 |
Common stock; par value $0.001; 100,000,000 shares authorized: issued 28,897,133 shares at December 31, 2012, and 28,670,424 at June 30, 2012; outstanding 28,106,796 shares and 27,882,224 shares as of December 31, 2012 and June 30, 2012, respectively |  | 28,897 |  | 28,670 |
Additional paid-in capital |  | 30,164,056 |  | 29,416,914 |
Retained earnings |  | 20,840,556 |  | 18,058,909 |
|  | 51,033,826 |  | 47,504,810 |
Treasury stock, at cost, 790,337 shares and 788,200 shares as of December 31, 2012 and June 30, 2012, respectively |  | (898,990 | ) | (882,022 | )
Total stockholders’ equity |  | 50,134,836 |  | 46,622,788 |
Total liabilities and stockholders’ equity |  | $ | 61,501,241 |  | $ | 58,955,486 |

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, |
|  | 2012 |  | 2011 |  | 2012 |  | 2011 |
Revenues |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 5,379,399 |  | $ | 4,231,201 |  | $ | 9,384,821 |  | $ | 7,679,796 |
Natural gas liquids |  | 86,556 |  | 182,971 |  | 206,167 |  | 371,426 |
Natural gas |  | 182,103 |  | 232,530 |  | 348,616 |  | 480,336 |
Total revenues |  | 5,648,058 |  | 4,646,702 |  | 9,939,604 |  | 8,531,558 |
Operating Costs |  |  |  |  |  |  |  |  |
Lease operating expenses |  | 419,328 |  | 412,470 |  | 735,497 |  | 615,387 |
Production taxes |  | 20,863 |  | 18,725 |  | 42,236 |  | 32,760 |
Depreciation, depletion and amortization |  | 350,119 |  | 280,795 |  | 647,036 |  | 517,686 |
Accretion of discount on asset retirement obligations |  | 17,751 |  | 19,616 |  | 38,858 |  | 36,588 |
General and administrative expenses * |  | 1,815,276 |  | 1,488,258 |  | 3,520,700 |  | 2,893,433 |
Total operating costs |  | 2,623,337 |  | 2,219,864 |  | 4,984,327 |  | 4,095,854 |
Income from operations |  | 3,024,721 |  | 2,426,838 |  | 4,955,277 |  | 4,435,704 |
Other |  |  |  |  |  |  |  |  |
Interest income |  | 5,614 |  | 6,712 |  | 11,230 |  | 13,958 |
Interest (expense) |  | (16,564 | ) | — |  | (32,992 | ) | — |
|  | (10,950 | ) | 6,712 |  | (21,762 | ) | 13,958 |
Net income before income taxes |  | 3,013,771 |  | 2,433,550 |  | 4,933,515 |  | 4,449,662 |
Income tax provision |  | 1,054,499 |  | 1,008,195 |  | 1,814,717 |  | 1,880,789 |
Net Income |  | $ | 1,959,272 |  | $ | 1,425,355 |  | $ | 3,118,798 |  | $ | 2,568,873 |
Dividends on Preferred Stock |  | 168,576 |  | 165,405 |  | 337,151 |  | 293,240 |
Net income available to common shareholders |  | $ | 1,790,696 |  | $ | 1,259,950 |  | $ | 2,781,647 |  | $ | 2,275,633 |
Basic |  | $ | 0.06 |  | $ | 0.05 |  | $ | 0.10 |  | $ | 0.08 |
Diluted |  | $ | 0.06 |  | $ | 0.04 |  | $ | 0.09 |  | $ | 0.07 |
Weighted average number of common shares |  |  |  |  |  |  |  |  |
Basic |  | 28,071,317 |  | 27,792,768 |  | 28,032,223 |  | 27,731,062 |
Diluted |  | 31,856,417 |  | 31,515,271 |  | 31,836,983 |  | 31,394,528 |

*General and administrative expenses for the three months ended December 31, 2012 and 2011 included non-cash stock-based compensation expense of $393,579 and $354,871, respectively. For the corresponding six month period’s non-cash stock-based compensation expense was $747,369 and $771,566, respectively.

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, |
|  | 2012 |  | 2011 |
Cash flows from operating activities |  |  |  |  |
Net Income |  | $ | 3,118,798 |  | $ | 2,568,873 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Depreciation, depletion and amortization |  | 667,461 |  | 517,686 |
Stock-based compensation |  | 747,369 |  | 771,566 |
Accretion of discount on asset retirement obligations |  | 38,858 |  | 36,588 |
Settlements of asset retirement obligations |  | (47,026 | ) | (30,969 | )
Deferred income taxes |  | 1,498,760 |  | 1,258,106 |
Deferred rent |  | (8,574 | ) | (6,829 | )
Changes in operating assets and liabilities: |  |  |  |  |
Receivables from oil and natural gas sales |  | (797,933 | ) | (402,023 | )
Receivables from income taxes and other |  | (116 | ) | 20,889 |
Due to/from joint interest partner |  | 40,050 |  | 6,854 |
Prepaid expenses and other current assets |  | 48,591 |  | (102,360 | )
Accounts payable and accrued expenses |  | (390,979 | ) | (307,079 | )
Royalties payable |  | (74,876 | ) | (122,225 | )
Income taxes payable |  | 115,801 |  | 93,279 |
Net cash provided by operating activities |  | 4,956,184 |  | 4,302,356 |
Cash flows from investing activities |  |  |  |  |
Proceeds from asset sales |  | 3,054,976 |  | — |
Capital expenditures for oil and natural gas properties |  | (4,013,430 | ) | (1,504,534 | )
Capital expenditures for other property and equipment |  | — |  | (12,778 | )
Other assets |  | (26,110 | ) | (23,657 | )
Net cash used in investing activities |  | (984,564 | ) | (1,540,969 | )
Cash flows from financing activities |  |  |  |  |
Proceeds from issuances of preferred stock, net |  | — |  | 6,930,535 |
Preferred stock dividends paid |  | (337,151 | ) | (293,240 | )
Purchases of treasury stock |  | (16,968 | ) | — |
Deferred loan costs |  | (16,211 | ) | — |
Net cash provided by (used in) financing activities |  | (370,330 | ) | 6,637,295 |
Net increase in cash and cash equivalents |  | 3,601,290 |  | 9,398,682 |
Cash and cash equivalents, beginning of period |  | 14,428,548 |  | 4,247,438 |
Cash and cash equivalents, end of period |  | $ | 18,029,838 |  | $ | 13,646,120 |

Our supplemental disclosures of cash flow information for the six months ended December 31, 2012 and 2011 are as follows:

|  | Six Months Ended |
|  | December 31, |
|  | 2012 |  | 2011 |
Income taxes paid |  | $ | 200,156 |  | $ | 513,581 |
Non-cash transactions: |  |  |  |  |
Change in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties |  | 31,885 |  | 449,146 |
Change in due to joint interest partner used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties |  | (435,833 | ) | — |
Change in accounts payable related to joint venture activities |  | — |  | 9,576 |
Oil and natural gas properties incurred through recognition of asset retirement obligations |  | 8,558 |  | 47,200 |

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 acquisition, exploitation and development of properties for the production of crude oil and natural gas. We acquire properties with known oil and natural gas resources and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2012 Annual Report on Form 10-K for the fiscal year ended June 30, 2012, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries: NGS Sub Corp and its wholly owned subsidiary, Tertiaire Resources Company, NGS Technologies, Inc., Evolution Operating Co., Inc. and Evolution Petroleum OK, Inc. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous period may include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported loss or stockholders’ equity.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Note 2 — Property and Equipment

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

|  | December 31, 2012 |  | June 30, 2012 |
Oil and natural gas properties |  |  |  |  |
Property costs subject to amortization |  | $ | 38,447,880 |  | $ | 40,874,244 |
Less: Accumulated depreciation, depletion, and amortization |  | (7,202,718 | ) | (6,440,166 | )
Unproved properties not subject to amortization |  | 9,031,522 |  | 6,042,094 |
Oil and natural gas properties, net |  | $ | 40,276,684 |  | $ | 40,476,172 |
Other property and equipment |  |  |  |  |
Furniture, fixtures and office equipment, at cost |  | 322,515 |  | 322,514 |
Less: Accumulated depreciation |  | (254,484 | ) | (230,243 | )
Other property and equipment, net |  | $ | 68,031 |  | $ | 92,271 |

Unproved properties not subject to amortization consists of unevaluated acreage and development costs of $9.0 million and $6.0 million as of December 31, 2012 and June 30, 2012, respectively, for our properties in the Mississippi Lime in Oklahoma. Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis. Based on this evaluation there were no impaired properties for the six months ended December 31, 2012. During the corresponding prior year period, we transferred approximately $2.2 million of impaired assets, reflecting principally Woodford Shale properties, from our unevaluated pool to our full cost pool.

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

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

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

Note 3 — Joint Interest Agreement

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

Our participation in this joint venture is reflected on our December 31, 2012 and June 30, 2012 balance sheets by the items below. Included in the $1.4 million June 30, 2012 advance to our joint interest operating partner is an accrued $1,142,716 drilling cash call, which is also reflected in the due to joint interest partner balance.

|  | December 31, 2012 |  | June 30, 2012 |
Advances to joint interest operating partner |  | $ | — |  | $ | 1,366,921 |
Due to joint interest partner |  | 1,383,991 |  | 3,217,975 |

Note 4 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the six months ended December 31, 2012:

|  | December 31, 2012 |  | June 30, 2012 |
Asset retirement obligations — beginning of period |  | $ | 968,677 |  | $ | 859,586 |
Liabilities sold |  | (170,433 | ) | — |
Liabilities incurred |  | 3,126 |  | 175,943 |
Liabilities settled |  | (18,820 | ) | (61,936 | )
Accretion of discount |  | 38,858 |  | 77,505 |
Revision of previous estimates |  | 5,432 |  | (82,421 | )
Asset retirement obligations — end of period |  | $ | 826,840 |  | $ | 968,677 |

Note 5 — Stockholders’ Equity

Common Stock

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

On September 6, 2012, the Board of Directors authorized and the Company issued 154,227 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award. Total unrecognized stock-based compensation expense of $1,223,020 related to the long-term incentive award will be recognized ratably over a four year period as the restricted common stock vests. See Note 6.

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On November 23, 2012, the Company issued 25,000 shares of restricted stock to a consultant. The value of the shares issued was $191,750, based on the fair market value on the date of issuance. The shares vest over a two year period. See Note 6.

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

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

Series A Cumulative Perpetual Preferred Stock

There were no sales during the six months ended December 31, 2012. During the six months ended December 31, 2011, we sold 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock with a liquidation preference of $25.00 per share, 220,000 of which were sold in an underwritten public offering and 97,319 shares of which were sold under an at-the-market sales agreement (ATM), providing aggregate net proceeds of $6,930,535 after market discounts, underwriting fees, legal and other expenses of the offerings. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to holders thereof. Optional redemption can only be made by us on or after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends, or by an acquirer under a change of control prior to such date at redemption prices ranging from $25.25 to $25.75 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, 2012 and 2011, we paid dividends of $337,151 and $293,240, respectively, to holders of our Series A Preferred Stock.

Note 6 — Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”). Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan. The 2004 Stock Plan authorized the issuance of 6,500,000 shares of common stock. No shares are available for grant under the 2003 Stock Plan and 800,914 shares remain available for grant under the 2004 Stock Plan as of December 31, 2012. We have not issued option awards since September of 2008.

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

Stock Options and Incentive Warrants

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

For the three months ended December 31, and 2012 stock-based compensation expense was $- and $59,410, respectively. For the six months ended December 31, 2012 and 2011, such expense was $26,274 and $232,139, respectively.

There were no Stock Options granted during the six months ended December 31, 2012 and 2011.

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2012, and the changes during the fiscal year:

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|  | Number of Stock Options and Incentive Warrants |  | Weighted Average Exercise Price |  | Aggregate Intrinsic Value (1) |  | Weighted Average Remaining Contractual Term (in years) |
Stock Options and Incentive Warrants outstanding at July 1, 2012 |  | 5,372,820 |  | $ | 1.83 |  |  |  |  |
Granted |  | — |  | — |  |  |  |  |
Exercised |  | (30,000 | ) | $ | 4.10 |  |  |  |  |
Cancelled or forfeited |  | — |  | — |  |  |  |  |
Expired |  | — |  | — |  |  |  |  |
Stock Options and Incentive Warrants outstanding at December 31, 2012 |  | 5,342,820 |  | $ | 1.82 |  | $ | 33,707,830 |  | 2.9 |
Vested or expected to vest at December 31, 2012 |  | 5,342,820 |  | $ | 1.82 |  | $ | 33,707,830 |  | 2.9 |
Exercisable at December 31, 2012 |  | 5,342,820 |  | $ | 1.82 |  | $ | 33,707,830 |  | 2.9 |

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($8.13 as of December 31, 2012) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 30,000 Stock Options exercised during the six months ended December 31, 2012 with an aggregate intrinsic value of $131,700.

A summary of the status of our unvested Stock Options and Incentive Warrants as of December 31, 2012 and the changes during the six months ended December 31, 2012, is presented below:

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

During the six months ended December 31, 2012 and 2011, there were 18,922 and 109,039 Stock Options and Incentive Warrants that vested with a total grant date fair value of $46,359 and $216,987, respectively.

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

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Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended December 31, 2012 and 2011 was $393,579 and $295,461, respectively. For the six months ended December 31, 2012 and 2011, such compensation expense was $721,095 and $539,427, respectively.

The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2012:

|  | Number of Restricted Shares |  | Weighted Average Grant-Date Fair Value |
Unvested at July 1, 2012 |  | 452,600 |  | $ | 5.16 |
Granted |  | 211,197 |  | $ | 7.88 |
Vested |  | (154,523 | ) | $ | 5.27 |
Forfeited |  | — |  | — |
Unvested at December 31, 2012 |  | 509,274 |  | $ | 6.25 |

For the 211,197 shares awarded above, the grant date fair value reflects the stock’s closing price on the first trading day before the grant date. See Note 5. At December 31, 2012, unrecognized stock compensation expense related to Restricted Stock grants totaled $3,062,390. Such unrecognized expense will be recognized over a weighted average period of 2.5 years.

Note 7 — Fair Value Measurement

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

The three levels are defined as follows:

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

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

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

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

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

Note 8 — Income Taxes

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

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the six months ended December 31, 2012. We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2007 through June 30, 2012.

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The Company recognized income tax expense of $1,054,499 and $1,008,195 for the three months ended December 31, 2012 and 2011, respectively, with corresponding effective rates of 35% and 41.4%.

We recognized income tax expense of $1,814,717 and $1,880,789 for the six months ended December 31, 2012 and 2011, respectively, with corresponding effective rates of 36.8% and 42.3%, respectively.

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

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, |
|  | 2012 |  | 2011 |  | 2012 |  | 2011 |
Numerator |  |  |  |  |  |  |  |  |
Net income available to common shareholders |  | $ | 1,790,696 |  | $ | 1,259,950 |  | $ | 2,781,647 |  | $ | 2,275,633 |
Denominator |  |  |  |  |  |  |  |  |
Weighted average number of common shares — Basic |  | 28,071,317 |  | 27,792,768 |  | 28,032,223 |  | 27,731,062 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |
Common stock warrants issued in connection with equity and financing transactions |  | 839 |  | 61,187 |  | 845 |  | 60,149 |
Stock Options and Incentive Warrants |  | 3,784,261 |  | 3,661,316 |  | 3,803,915 |  | 3,603,317 |
Total weighted average dilutive securities |  | 3,785,100 |  | 3,722,503 |  | 3,804,760 |  | 3,663,466 |
Weighted average number of common shares and dilutive potential common shares used in diluted EPS |  | 31,856,417 |  | 31,515,271 |  | 31,836,983 |  | 31,394,528 |
Net income per common share — Basic |  | $ | 0.06 |  | $ | 0.05 |  | $ | 0.10 |  | $ | 0.08 |
Net income per common share — Diluted |  | $ | 0.06 |  | $ | 0.04 |  | $ | 0.09 |  | $ | 0.07 |

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 |  | $ | 2.50 |  | 1,165 |
Stock Options and Incentive Warrants |  | $ | 1.82 |  | 5,342,820 |
Total |  | $ | 1.82 |  | 5,343,985 |

Outstanding potentially dilutive securities as of December 31, 2011 were as follows:

Outstanding Potential Dilutive Securities |  | Weighted Average Exercise Price |  | Outstanding at December 31, 2011 |
Common stock warrants issued in connection with equity and financing transactions |  | $ | 2.50 |  | 92,365 |
Stock Options and Incentive Warrants |  | $ | 1.83 |  | 5,372,820 |
Total |  | $ | 1.84 |  | 5,465,185 |

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Note 10 - Unsecured Revolving Credit Agreement

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

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

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

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

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

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

As of December 31, 2012, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000. The Company was in compliance with all the covenants of the Credit Agreement.

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

Note 11 — Commitments and Contingencies

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

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, 2012 under this operating lease are as follows:

For the twelve months ended December 31, |  |  |
2013 |  | $ | 159,011 |
2014 |  | 159,011 |
2015 |  | 159,011 |
Thereafter |  | 92,756 |
Total |  | $ | 569,789 |

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Rent expense for the three months ended December 31, 2012 and 2011 was $36,808 and $36,808, respectively. For the corresponding six month periods of 2012 and 2011 rent expense was $73,617 and $73,617, respectively.

Employment Contracts. We have employment agreements with the Company’s three named executive officers. The employment contracts provide for a severance package for termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination. The total contingent obligation under the employment contracts as of December 31, 2012 is approximately $663,000.

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, 2012 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2012 Annual Report on Form 10-K for the year ended June 30, 2012 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation.

Executive Overview

General

We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. We acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.

We are focused on increasing underlying net asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including approximately 24% beneficially owned by all of our directors, officers and employees.

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

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

· Enhanced Oil Recovery (EOR),

· Bypassed Primary Resources, and

· Unconventional Reservoir Development.

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

Highlights for our Second Quarter Fiscal 2013 and Project Update

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

“Q1-13” & “prior quarter” and “sequential” prior quarter is the three months ended September 30, 2012, the company’s 1 st quarter of fiscal 2013.

“Q2-12” & “year-ago quarter” is the three months ended December 31, 2011, the company’s 2 nd quarter of fiscal 2012.

Operations

· Q2-13 posted record earnings per share from recurring operations*, increasing 81% sequentially and 42% over the year-ago quarter. Increases were largely driven by higher crude oil volumes, partially offset by declining prices compared to the year-ago quarter.

· Revenues set an all-time record, increasing 32% sequentially and 22% over the year-ago quarter. Crude oil volumes increased 34% sequentially and 39% over the year-ago quarter, while crude prices were unchanged sequentially and 9% less than the year-ago quarter.

· Record crude oil volumes increased to 82% of total volumes from 73% in the prior quarter and 72% in the year-ago quarter. Including NGL’s, liquids volumes were 85% of total volumes, compared to 80% in the prior quarter and 78% in the year-ago quarter.

· Field margins increased 33% sequentially and 24% over the year-ago quarter to $4.8 million. On a BOE basis, field margins increased 11% sequentially and 1% over the year-ago quarter to $76/BOE.

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

Projects

Delhi EOR Project — Northeast Louisiana

· Delhi Field sales volumes increased 36% over the prior quarter and 39% over the year-ago quarter to a record 509 BOPD net to our 7.4% royalty interest (6,872 gross BOPD). Sequential and comparable year-ago improvements were due to record high oil production in response to CO 2 injections across a larger part of the field. Sequential improvement also resulted from restoring production volumes that were cut back by the operator during most of the first fiscal quarter due to high ambient temperatures that limited the plant’s ability to recycle CO 2 for re-injection. Continued lower ambient temperatures that began in September 2012 remedied the issue in the near term, while additional cooling capacity is expected to be installed by the operator before the resumption of hot weather next summer.

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

· Realized oil prices at Delhi were sequentially unchanged and 9% lower from the year-ago quarter, averaging $104.43/BO in the current quarter. Realized prices were $103.78/BO in the previous quarter and $115.07 in the year-ago quarter.

· Delhi’s LLS pricing continues to command a premium. Realized Delhi prices were 16%, 12% and 24% higher than average realized oil prices in our other fields during the current, previous and year-ago quarters, respectively.

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2013 development revised. Calendar 2013 capital expenditures were recently refocused by the operator to further develop the western half of the Field where the flood has already been installed. The operator is currently remapping the field reservoirs to incorporate extensive 3-D seismic evaluation, and we believe this work may quantify upside potential in the Field not reflected in the June 2012 reserves.

Mississippian Lime — Kay County, OK

· Initial Development. We completed the drilling and hydraulic fracturing of the Sneath #1H horizontal production well and began dewatering operations at the end of October 2012. The Hendrickson #1H horizontal well was similarly completed and dewatering operations began at the end of November. These wells are the first two of 114 gross probable drilling locations assigned by our independent reservoir engineer. We own a 45% working interest in the Sneath and a 36.6% working interest in the Hendrickson.

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

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

· Current drilling and completion practices. In our area, industry has largely drilled horizontal wells into the upper section of the Mississippi Lime and completed with multiple stage hydraulic fracture treatments. The Sneath and Hendrickson wells were completed in this fashion, both wells being horizontally drilled high in the formation and targeting the formation just below the “Cherty” top layers of the Mississippi Limestone, followed by 10-12 stages of hydraulic fracturing each.

· Necessary de-pressuring continues. Our Sneath and Hendrickson wells are exhibiting two characteristics we believe are prerequisites for a successful horizontal MS Lime producer, those being large initial volumes of salt water production, with minimal amounts of hydrocarbons, and declining bottom-hole pressures. Declining pressure suggests that the well’s completion is contained within the target formation, as desired, and not connected to a water filled formation outside of the MS Lime, which is unfavorable. When declining pressure is present, larger amounts of salt water production suggest a potentially large, interconnected fracture system that provides access to the oil and gas reservoir, which is very favorable.

· Results to Date. Both wells began producing water, as expected, at rates of less than 3000 barrels per day. The operator has gradually increased dewatering rates and reservoir pressure has gradually declined as expected with small, but generally increasing, amounts of entrained oil and gas production. We subsequently learned from another operator of successful MS Lime wells that dewatering rates up to 10,000 barrels per day for an extended period are not unusual in our prospect area. Accordingly, our operator is further increasing dewatering rates to match best practices in the play. We are cautiously encouraged by the high water production rates entrained with some hydrocarbons, and steady but slow pressure decline, that suggest, but do not guarantee, our wells are connected to a large and contained fracture system within the MS Lime hydrocarbon bearing reservoir.

· We patiently wait and watch before allocating more capital. Our joint venture agreement with Orion Exploration initially called for the drilling of at least six gross wells by mid-April 2013. Due to the longer than expected dewatering and depressuring phase we are experiencing with the Sneath and Hendrickson wells, we expect to delay the beginning of additional drilling until later this fiscal year, pending results of those first two wells, with significant development drilling projected for Fiscal 2014.

GARP ®

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

· Efforts expanded through property acquisitions. As applications to date continue to demonstrate the effectiveness of our technology, we recently began a program to acquire abandoned wells that offer good potential for renewed production utilizing our technology.

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Other Fields

· Two sales of noncore assets in the Giddings Field were completed during the quarter, including a portion of our producing assets and most of our undeveloped reserves in the Giddings Field. Consistent with our election to divest noncore assets in order to better focus capital and staff on projects with higher near term value potential, we initiated a formal sales process for our nonGARP® assets in the Giddings Field in Texas. Two Giddings Field asset sales were completed during Q2-13, including most of our non-GARP® production and undeveloped reserves in the Giddings Field. The combined adjusted sales price was approximately $3.1 million before transaction costs, plus contingent payments based on future drilling activity. The larger sale for $2.8 million was completed December 24 th, while the smaller sale was completed in early November. Accordingly, Q2-13 results included most of the production, revenue and operating expense for the divested assets. Had the divestments been completed at the beginning of the quarter, net production in the Giddings Field would have been reduced by 75%, or 125 net BOE per day, to 42 net BOE per day. Similarly, approximately $400,000 of revenue, $145,000 of direct well expense (using the company’s average $5.24/BOE depletion rate) and $255,000 of pre-tax well income ($22/BOE) would have been absent in the current quarter’s results. The divested properties were high in natural gas and NGL content, averaging 80% of production volumes in the current quarter, and included approximately 350 MBOE of proved developed reserves and 1.8 MMBOE of proved undeveloped reserves as of June 30, 2012. Sale proceeds and staff are already being redeployed to our Mississippian Lime and GARP® projects. The remaining noncore assets in the Giddings Field are being offered for sale, excluding certain wells in which our GARP® technology has been installed, and excluding our minor royalty and reversionary interests in the Woodbine play in northern Grimes County.

Liquidity and Capital Resources

At December 31, 2012, our working capital was $18 million, compared to working capital of $11.7 million at June 30, 2012. The $6.3 million increase in working capital since June 30, 2012 was due primarily to increases of $3.6 million in cash and $0.8 million in accounts receivable together with decreases of $1.8 million in due joint interest partner and $0.4 million in accrued compensation.

Cash Flows from Operating Activities

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.

For the six months ended December 31, 2011, $4.3 million of cash flows was provided by operating activities, reflecting $5.1 million provided by operations before $0.8 million was used in working capital. Of the $5.1 million provided before working capital changes, $2.6 million was due to net income and $2.5 million was attributable 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, 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 its Giddings exploration and production properties.

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2011, was $1.5 million, primarily for a work over on the Dodd well in Grimes County and the drilling of four new wells in the Lopez Field in South Texas.

Oil and gas capital expenditures incurred were $3.6 million and $2.0 million, respectively, for the six months ended December 31, 2012 and 2011. These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

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Cash Flows from Financing Activities

In the six months ended December 31, 2012, we paid preferred dividends of $0.3 million.

During the six months ended December 31, 2011, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A perpetual preferred stock after all offering costs and we paid $0.3 million of dividends thereon.

Capital Budget

Our approved fiscal 2013 Base Plan provides for up to $10 million of capital expenditures. Due to the delay in drilling additional Mississippian Lime wells, a substantial portion of the 2013 Plan is likely to carry over into Fiscal 2014, and the remaining balance of expected Fiscal 2013 capital expenditures can be funded from our existing working capital of $18.1 million at December 31, 2012. We expect to fund any increases over the fiscal 2013 Base Plan out of working capital, internally generated funds from operations, joint ventures, project financing, selective divestments of noncore assets or other appropriate financings, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Results of Operations

Three month period ended December 31, 2012 and 2011

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

|  | Three Months Ended December 31, |  |  |  | % |
|  | 2012 |  | 2011 |  | Variance |  | Change |
Sales Volumes, net to the Company: |  |  |  |  |  |  |  |  |
Crude oil (Bbl) |  | 52,270 |  | 37,514 |  | 14,756 |  | 39.3 | %
NGLs (Bbl) |  | 2,378 |  | 3,145 |  | (767 | ) | (24.4 | )%
Natural gas (Mcf) |  | 56,210 |  | 69,880 |  | (13,670 | ) | (19.6 | )%
Crude oil, NGLs and natural gas (BOE) |  | 64,016 |  | 52,306 |  | 11,710 |  | 22.4 | %
Revenue data: |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 5,379,399 |  | $ | 4,231,201 |  | $ | 1,148,198 |  | 27.1 | %
NGLs |  | 86,556 |  | 182,971 |  | (96,415 | ) | (52.7 | )%
Natural gas |  | 182,103 |  | 232,530 |  | (50,427 | ) | (21.7 | )%
Total revenues |  | $ | 5,648,058 |  | $ | 4,646,702 |  | $ | 1,001,356 |  | 21.5 | %
Average price: |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) |  | $ | 102.92 |  | $ | 112.79 |  | $ | (9.87 | ) | (8.8 | )%
NGLs (per Bbl) |  | 36.40 |  | 58.18 |  | (21.78 | ) | (37.4 | )%
Natural gas (per Mcf) |  | 3.24 |  | 3.33 |  | (0.09 | ) | (2.7 | )%
Crude oil, NGLs and natural gas (per BOE) |  | $ | 88.23 |  | $ | 88.84 |  | $ | (0.61 | ) | (0.7 | )%
Expenses (per BOE) |  |  |  |  |  |  |  |  |
Lease operating expenses |  | $ | 6.55 |  | $ | 7.89 |  | $ | (1.34 | ) | (17.0 | )%
Production taxes |  | $ | 0.33 |  | $ | 0.36 |  | $ | (0.03 | ) | (8.3 | )%
Depletion expense on oil and natural gas properties (a) |  | $ | 5.24 |  | $ | 5.20 |  | $ | 0.04 |  | 0.8 | %

(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $14,462 and $8,723, for the three months ended December 31, 2012 and 2011, respectively.

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Net Income Available to Common Shareholders. For the three months ended December 31, 2012, we generated 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. This compares to a net income of $1,259,950, or $0.04 per diluted share, (which includes $354,871 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,646,702 for the year-ago quarter. This increase in net income is primarily due to higher oil revenue partially offset by increased operating expenses. Additional details of the components of net income are explained in greater detail below.

Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended December 31, 2012 increased 22.4% to 64,016 BOE’s compared to 52,306 BOE’s for the year-ago quarter. This 11,710 volume increase primarily reflects production and sales volumes increases in Delhi and South Texas fields, partially offset by a decrease in our Giddings properties reflecting a decrease in natural gas volume. Our crude oil sales volumes for the current quarter include 46,815 from our interests in Delhi and 5,455 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 33,698 barrels from our interests in Delhi and 3,816 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the three months ended December 31, 2012 and 2011, all from the Giddings Field, and declined 24% to 2,378 barrels. Current quarter natural gas volumes, virtually all produced at Giddings, decreased 20% to 56,210 mcf from 69,880 in the year-ago quarter. For the current quarter, there was no gas production from our now shut in Woodford properties that produced 1,256 mcf during the year-ago quarter.

Petroleum Revenues. Crude oil, NGL and natural gas revenues totaling $5.6 million for the current quarter increased $1.0 million, or 22%, from $4.6 million in the year-ago quarter due to 22% higher sales volumes with virtually no change in price. Prices per BOE were $88.23 and $88.84 respectively, for the current and year-ago quarter.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes for the current quarter increased $8,996 or 2%, to $440,191 compared to the year-ago quarter. This increase is principally due to increased expenses at the Mississippi Lime field, where three wells were completed during the current quarter, and the Giddings field, partially offset by lower expenses at the Lopez and Woodford fields. Lease operating expense and production tax per barrel of oil equivalent decreased 17% from $8.24 per BOE during the year-ago quarter to $6.88 per BOE in the current quarter.

General and Administrative Expenses (“G&A”). G&A expenses increased 22% to $1.8 million during the three months ended December 31, 2012 from $1.5 million in the year-ago quarter. The increase reflects $96,000 for higher bonus and other personnel costs, $72,000 of transaction expenses related to recent oil and gas property sales, increased legal and litigation expenses of $65,000 and $40,000 for board of director fees. Stock-based compensation was $393,579 (22% of total G&A) for the current quarter compared to $354,871 (24% of total G&A) for the year-ago quarter. Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased by 25% to $350,119 for the three months ended December 31, 2012, compared to $280,795 for the year-ago quarter. This change was principally due to a 22% volume increase. The current quarter’s depletion rate was $5.24 compared to $5.20 in the year-ago quarter.

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Six month period ended December 31, 2012 and 2011

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

|  | Six Months Ended December 31, |  |  |  | % |
|  | 2012 |  | 2011 |  | Variance |  | Change |
Sales Volumes, net to the Company: |  |  |  |  |  |  |  |  |
Crude oil (Bbl) |  | 91,352 |  | 70,674 |  | 20,678 |  | 29.3 | %
NGLs (Bbl) |  | 5,759 |  | 6,666 |  | (907 | ) | (13.6 | )%
Natural gas (Mcf) |  | 122,079 |  | 130,597 |  | (8,518 | ) | (6.5 | )%
Crude oil, NGLs and natural gas (BOE) |  | 117,457 |  | 99,106 |  | 18,351 |  | 18.5 | %
Revenue data: |  |  |  |  |  |  |  |  |
Crude oil |  | $ | 9,384,821 |  | $ | 7,679,796 |  | $ | 1,705,025 |  | 22.2 | %
NGLs |  | 206,167 |  | 371,426 |  | (165,259 | ) | (44.5 | )%
Natural gas |  | 348,616 |  | 480,336 |  | (131,720 | ) | (27.4 | )%
Total revenues |  | $ | 9,939,604 |  | $ | 8,531,558 |  | $ | 1,408,046 |  | 16.5 | %
Average price: |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) |  | $ | 102.73 |  | $ | 108.67 |  | $ | (5.93 | ) | (5.5 | )%
NGLs (per Bbl) |  | 35.80 |  | 55.72 |  | (19.92 | ) | (35.8 | )%
Natural gas (per Mcf) |  | 2.86 |  | 3.68 |  | (0.82 | ) | (22.2 | )%
Crude oil, NGLs and natural gas (per BOE) |  | $ | 84.62 |  | $ | 86.09 |  | $ | (1.47 | ) | (1.7 | )%
Expenses (per BOE) |  |  |  |  |  |  |  |  |
Lease operating expenses |  | $ | 6.26 |  | $ | 6.21 |  | $ | 0.05 |  | 0.8 | %
Production taxes |  | $ | 0.36 |  | $ | 0.33 |  | $ | 0.03 |  | 9.1 | %
Depletion expense on oil and natural gas properties (a) |  | $ | 5.28 |  | $ | 5.06 |  | $ | 0.22 |  | 4.3 | %

(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $26,711 and $16,552 for the six months ended December 31, 2012 and 2011, respectively.

Net Income Available to Common Shareholders. For the six months ended December 31, 2012, we generated 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. This compares to a net income of $2,275,633, or $0.07 per diluted share, (which includes $771,566 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $8,531,558 for the six months ended December 31, 2011. The net income increase was primarily attributable to increased oil revenue and lower income taxes partly offset by higher operating expenses. Additional details of earnings components are explained in greater detail below.

Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the six months ended December 31, 2012 increased 19% to 117,457 BOE’s compared to 99,106 BOE’s for the six months ended December 31, 2011 due to significant production and sales volume increases in Delhi Field together with production from four Lopez wells in the prior year, offset by a slight production decrease at the Giddings Field. Our crude oil sales volumes for the six months ended December 31, 2012 included 81,268 barrels from our interests in Delhi and 10,084 barrels from our properties in the Giddings and Lopez Field. Our crude oil sales volumes for the six months ended December 31, 2011 included 63,645 barrels from our interests in Delhi and 7,029 barrels primarily from our properties in the Giddings Field. Our NGL volumes for the six months ended December 31, 2012 and 2011 were from our properties in the Giddings Field, and declined 14% to 5,760 barrels. For the corresponding periods, natural gas volumes, from our Giddings Field and Oklahoma properties decreased 7% to 122.1 mmcf.

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Petroleum Revenues. Crude oil, NGL and natural gas revenues for the six months ended December 31, 2012 increased 17% compared to the six months ended December 31, 2011. This was due to 19% higher sales volumes, as mentioned above, offset by a 2% price decrease. The average price received per BOE was $86.09 per BOE for the six months ended December 31, 2011 compared to $84.62 per BOE for the six months ended December 31, 2012.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes of $777,733 for the six months ended December 31, 2012 increased $129,586, or 20%, compared to $648,147 for the six months ended December 31, 2011. The increase reflects higher expenses in the Mississippi Lime due to the three wells completed in the current year and increased Giddings expense due to GARP® , partially offset by declines at Lopez and Woodford. Lease operating expense and production tax per barrel of oil equivalent increased 2% from $6.54 per BOE during the six months ended December 31, 2011, to $6.62 per BOE during the six months ended December 31, 2012.

General and Administrative Expenses (“G&A”). G&A expenses increased 22% from $2.9 million during the six months ended December 31, 2011 to $3.5 million during the six months ended December 31, 2012. The increase was due principally due to $200,000 for higher bonus and other personnel costs, $151,000 of legal and litigation expenses, $81,000 for board of director fees, higher management consulting expense of $74,000, and $72,000 in transaction expenses related to oil and gas property sales. Stock-based compensation was $747,369 (22% of total G&A) for the six months ended December 31, 2012, compared to $771,566 (27% of total G&A) for the six months ended December 31, 2011. Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased by 25% to $647,036 for the six months ended December 31, 2012, compared to $517,686 for the six months ended December 31, 2011. The increase was primarily due to higher sales volumes as noted above. For the six months ended December 31, 2012 the depletion rate was $5.28 per BOE compared to $5.06 per BOE for the corresponding prior year period.

Inflation. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures. During fiscal 2012, we saw material increases in certain oil field services and materials. Product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties. General worldwide economic conditions continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas. If demand decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward. In addition, our lease operating expenses and their percentage of our revenues are likely to increase as our working interest production increases at our Mississippian Lime Play, reversion of our back-interest at Delhi or other additions to our working interest production that would dilute extraordinary margins we have enjoyed from our mineral and overriding royalty interests at Delhi.

Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the quarter ending December 31, 2012.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended December 31, 2012, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2012 except as noted below. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for our fiscal year ended June 30, 2012.

Interest Rate Risk

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

Commodity Price Risk

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

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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, 2012 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, 2012 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 12 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2012 Annual Report. During the six months ended December 31, 2012, there were no material developments in the status of those proceedings. We believe that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on our financial position or on our results of operations.

ITEM 1A. RISK FACTORS

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

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

None.

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

Period |  | (a) Total Number of Shares (or Units) Purchased |  | (b) Average Price Paid per Share (or Units) |  | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |  | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
December 1 to December 31, 2012 |  | 2,137 shares of Common Stock |  | $ | 7.94 |  | 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.
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 11, 2013

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