10-Q 1 epm2015q310-q.htm 10-Q
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
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: ý 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: ý 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: ý
The number of shares outstanding of the registrant’s common stock, par value $0.001, as of May 5, 2015, was 32,909,331.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS

|  | Page
PART I. FINANCIAL INFORMATION | 2
ITEM 1. | UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS | 2
| Unaudited Consolidated Condensed Balance Sheets as of March 31, 2015 and June 30, 2014 | 2
| Unaudited Consolidated Condensed Statements of Operations for the three months ended March 31, 2015 and 2014 and the nine months ended March 31, 2015 and 2014 | 3
| Unaudited Consolidated Condensed Statements of Cash Flows for the nine months ended March 31, 2015 and 2014 | 4
| Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the nine months ended March 31, 2015 | 5
| Notes to Unaudited Consolidated Condensed Financial Statements | 6
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 17
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 25
ITEM 4. | CONTROLS AND PROCEDURES | 25
PART II. OTHER INFORMATION | 26
ITEM 1. | LEGAL PROCEEDINGS | 26
ITEM 1A. | RISK FACTORS | 26
ITEM 2. | UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS | 26
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES | 26
ITEM 4. | MINE SAFETY DISCLOSURES | 26
ITEM 5. | OTHER INFORMATION | 26
ITEM 6. | EXHIBITS | 27
SIGNATURES |  | 28

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Table of Contents
PART I — FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited)

| March 31, 2015 |  | June 30, 2014
Assets |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents | $ | 20,391,495 |  |  | $ | 23,940,514 |
Receivables | 2,686,686 |  |  | 1,457,212 |
Deferred tax asset | 159,624 |  |  | 159,624 |
Prepaid expenses and other current assets | 650,826 |  |  | 747,453 |
Total current assets | 23,888,631 |  |  | 26,304,803 |
Oil and natural gas property and equipment, net (full-cost method of accounting) | 40,349,940 |  |  | 37,822,070 |
Other property and equipment, net | 308,411 |  |  | 424,827 |
Total property and equipment | 40,658,351 |  |  | 38,246,897 |
Other assets | 662,247 |  |  | 464,052 |
Total assets | $ | 65,209,229 |  |  | $ | 65,015,752 |
Liabilities and Stockholders’ Equity |  |  |  |  |
Current liabilities |  |  |  |  |
Accounts payable | $ | 4,556,114 |  |  | $ | 441,722 |
State and federal income taxes payable | 116,343 |  |  | — |
Accrued liabilities and other | 789,692 |  |  | 2,558,004 |
Total current liabilities | 5,462,149 |  |  | 2,999,726 |
Long term liabilities |  |  |  |  |
Deferred income taxes | 10,834,844 |  |  | 9,897,272 |
Asset retirement obligations | 749,252 |  |  | 205,512 |
Deferred rent | 22,861 |  |  | 35,720 |
Total liabilities | 17,069,106 |  |  | 13,138,230 |
Commitments and contingencies (Note 15) |  |  |  |  |
Stockholders’ equity |  |  |  |  |
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at March 31, 2015 and June 30, 2014 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 and outstanding 32,909,331 shares and 32,615,646 as of March 31, 2015 and June 30, 2014, respectively | 32,909 |  |  | 32,615 |
Additional paid-in capital | 36,489,885 |  |  | 34,632,377 |
Retained earnings | 11,617,012 |  |  | 17,212,213 |
Total stockholders’ equity | 48,140,123 |  |  | 51,877,522 |
Total liabilities and stockholders’ equity | $ | 65,209,229 |  |  | $ | 65,015,752 |

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 March 31, |  | Nine Months Ended March 31,
| 2015 |  | 2014 |  | 2015 |  | 2014
Revenues |  |  |  |  |  |  |  |  |  |  |
Delhi field | $ | 7,039,868 |  |  | $ | 4,185,156 |  |  | $ | 18,553,301 |  |  | $ | 12,745,203 |
Artificial lift technology | 24,821 |  |  | 151,052 |  |  | 203,913 |  |  | 483,037 |
Other properties | — |  |  | 798 |  |  | 20,369 |  |  | 134,754 |
Total revenues | 7,064,689 |  |  | 4,337,006 |  |  | 18,777,583 |  |  | 13,362,994 |
Operating costs |  |  |  |  |  |  |  |  |  |  |
Production costs - Delhi field | 2,932,946 |  |  | — |  |  | 5,750,812 |  |  | — |
Production costs - artificial lift technology | 267,906 |  |  | 209,742 |  |  | 656,819 |  |  | 526,712 |
Production costs - other properties | 639 |  |  | 143,887 |  |  | 98,051 |  |  | 481,697 |
Depreciation, depletion and amortization | 1,138,502 |  |  | 311,815 |  |  | 2,425,609 |  |  | 948,656 |
Accretion of discount on asset retirement obligations | 10,924 |  |  | 9,631 |  |  | 23,697 |  |  | 34,977 |
General and administrative expenses * | 1,467,782 |  |  | 2,304,397 |  |  | 4,578,876 |  |  | 6,875,430 |
Restructuring charges ** | — |  |  | — |  |  | (5,431 | ) |  | 1,332,186 |
Total operating costs | 5,818,699 |  |  | 2,979,472 |  |  | 13,528,433 |  |  | 10,199,658 |
Income from operations | 1,245,990 |  |  | 1,357,534 |  |  | 5,249,150 |  |  | 3,163,336 |
Other |  |  |  |  |  |  |  |  |  |  |
Interest income | 7,401 |  |  | 7,383 |  |  | 27,826 |  |  | 22,787 |
Interest (expense) | (24,625 | ) |  | (17,605 | ) |  | (55,244 | ) |  | (50,700 | )
Income before income taxes | 1,228,766 |  |  | 1,347,312 |  |  | 5,221,732 |  |  | 3,135,423 |
Income tax provision | 494,180 |  |  | 423,612 |  |  | 2,118,218 |  |  | 1,148,155 |
Net income attributable to the Company | $ | 734,586 |  |  | $ | 923,700 |  |  | $ | 3,103,514 |  |  | $ | 1,987,268 |
Dividends on preferred stock | 168,575 |  |  | 168,575 |  |  | 505,726 |  |  | 505,726 |
Net income available to common stockholders | $ | 566,011 |  |  | $ | 755,125 |  |  | $ | 2,597,788 |  |  | $ | 1,481,542 |
Earnings per common share |  |  |  |  |  |  |
Basic | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.05 |
Diluted | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.05 |
Weighted average number of common shares |  |  |  |  |  |  |  |  |  |  |
Basic | 32,861,001 |  |  | 32,358,163 |  |  | 32,789,157 |  |  | 30,328,344 |
Diluted | 32,958,218 |  |  | 32,732,049 |  |  | 32,909,981 |  |  | 32,503,460 |

* General and administrative expenses for the three months ended March 31, 2015 and 2014 included non-cash stock-based compensation expense of $227,507 and $444,981, respectively. For the corresponding nine month periods, non-cash stock-based compensation expense was $715,864 and $1,134,841, respectively.
** Restructuring charges for the nine months ended March 31, 2014 included non-cash stock-based compensation expense of $376,365. For the three months ended March 31, 2014, restructuring charges contained no stock-based compensation expense.
See accompanying notes to consolidated condensed financial statements.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)

| Nine Months Ended March 31,
| 2015 |  | 2014
Cash flows from operating activities |  |  |  |  |
Net income attributable to the Company | $ | 3,103,514 |  |  | $ | 1,987,268 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Depreciation, depletion and amortization | 2,462,087 |  |  | 980,589 |
Stock-based compensation | 715,864 |  |  | 1,134,841 |
Stock-based compensation related to restructuring | — |  |  | 376,365 |
Accretion of discount on asset retirement obligations | 23,697 |  |  | 34,977 |
Settlements of asset retirement obligations | (223,565 | ) |  | (73,646 | )
Deferred income taxes | 937,572 |  |  | 998,367 |
Deferred rent | (12,859 | ) |  | (12,859 | )
Changes in operating assets and liabilities: |  |  |  |  |
Receivables from oil and natural gas sales | (1,007,058 | ) |  | 88,146 |
Receivables other | (222,416 | ) |  | (3,679 | )
Due from joint interest partner | — |  |  | 70,083 |
Prepaid expenses and other current assets | 96,627 |  |  | (376,501 | )
Accounts payable and accrued expenses | 629,760 |  |  | 690,360 |
Income taxes payable | 116,343 |  |  | (233,548 | )
Net cash provided by operating activities | 6,619,566 |  |  | 5,660,763 |
Cash flows from investing activities |  |  |  |  |
Proceeds from asset sales | 389,166 |  |  | 542,349 |
Maturity of certificate of deposit | — |  |  | 250,000 |
Capital expenditures for oil and natural gas properties | (2,432,424 | ) |  | (989,616 | )
Capital expenditures for other property and equipment | (320,936 | ) |  | (12,793 | )
Other assets | (183,877 | ) |  | (181,751 | )
Net cash used in investing activities | (2,548,071 | ) |  | (391,811 | )
Cash flows from financing activities |  |  |  |  |
Proceeds on exercise of stock options | 141,600 |  |  | 3,162,801 |
Cash dividends to preferred stockholders | (505,726 | ) |  | (505,726 | )
Cash dividends to common stockholders | (8,192,989 | ) |  | (6,462,269 | )
Stock exchanged for payroll tax liabilities | (63,556 | ) |  | (1,591,765 | )
Tax benefits related to stock-based compensation | 1,063,827 |  |  | 108,473 |
Deferred loan costs | (63,737 | ) |  | (40,334 | )
Other | 67 |  |  | 6,850 |
Net cash used in financing activities | (7,620,514 | ) |  | (5,321,970 | )
Net decrease in cash and cash equivalents | (3,549,019 | ) |  | (53,018 | )
Cash and cash equivalents, beginning of period | 23,940,514 |  |  | 24,928,585 |
Cash and cash equivalents, end of period | $ | 20,391,495 |  |  | $ | 24,875,567 |

Supplemental disclosures of cash flow information: | Nine Months Ended March 31,
| 2015 |  | 2014
Income taxes paid | $ | 100,000 |  |  | $ | 755,941 |
Non-cash transactions: |  |  |  |  |
Change in accounts payable used to acquire property and equipment | 1,877,830 |  |  | (241,094 | )
Oil and natural gas property costs incurred through recognition of asset retirement obligations | 573,689 |  |  | 45,172 |
Previously acquired Company common shares swapped by holders to pay stock option exercise price | — |  |  | 618,606 |

See accompanying notes to consolidated condensed financial statements.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statement of Changes in Stockholders' Equity
For the Nine Months Ended March 31, 2015
(Unaudited)

| Preferred |  | Common Stock |  |  |  |  |  |  |  |
| Additional Paid-in Capital |  | Retained Earnings |  | Treasury Stock |  | Total Stockholders' Equity
| Shares |  | Par Value |  | Shares |  | Par Value |
Balance, June 30, 2014 | 317,319 |  |  | $ | 317 |  |  | 32,615,646 |  |  | $ | 32,615 |  |  | $ | 34,632,377 |  |  | $ | 17,212,213 |  |  | $ | — |  |  | $ | 51,877,522 |
Issuance of restricted common stock | — |  |  | — |  |  | 213,466 |  |  | 214 |  |  | (147 | ) |  | — |  |  | — |  |  | 67 |
Exercise of stock options | — |  |  | — |  |  | 87,000 |  |  | 87 |  |  | 141,513 |  |  | — |  |  | — |  |  | 141,600 |
Stock exchanged for payroll tax liabilities | — |  |  | — |  |  | (6,781 | ) |  | — |  |  | — |  |  | — |  |  | (63,556 | ) |  | (63,556 | )
Retirements of treasury stock | — |  |  | — |  |  | — |  |  | (7 | ) |  | (63,549 | ) |  | — |  |  | 63,556 |  |  | — |
Stock-based compensation | — |  |  | — |  |  | — |  |  | — |  |  | 715,864 |  |  | — |  |  | — |  |  | 715,864 |
Tax benefits related to stock-based compensation | — |  |  | — |  |  | — |  |  | — |  |  | 1,063,827 |  |  | — |  |  | — |  |  | 1,063,827 |
Net income attributable to the Company | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 3,103,514 |  |  | — |  |  | 3,103,514 |
Common stock cash dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (8,192,989 | ) |  | — |  |  | (8,192,989 | )
Preferred stock cash dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (505,726 | ) |  | — |  |  | (505,726 | )
Balance, March 31, 2015 | 317,319 |  |  | $ | 317 |  |  | 32,909,331 |  |  | $ | 32,909 |  |  | $ | 36,489,885 |  |  | $ | 11,617,012 |  |  | $ | — |  |  | $ | 48,140,123 |

See accompanying notes to consolidated condensed financial statements.
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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 1 — Organization and Basis of Preparation
Nature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of incremental oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology.
Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2014 Annual Report on Form 10-K for the fiscal year ended June 30, 2014, 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. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income 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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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 2 — Receivables
As of March 31, 2015 and June 30, 2014 our receivables consisted of the following:

| March 31, 2015 |  | June 30, 2014
Receivables from oil and gas sales | $ | 2,463,204 |  |  | $ | 1,456,146 |
Receivable from insurer recovering litigation costs | 206,895 |  |  | — |
Other | 16,587 |  |  | 1,066 |
Total receivables | $ | 2,686,686 |  |  | $ | 1,457,212 |

Note 3 — Prepaid Expenses and Other Current Assets
As of March 31, 2015 and June 30, 2014 our prepaid expenses and other current assets consisted of the following:

| March 31, 2015 |  | June 30, 2014
Prepaid insurance | $ | 93,497 |  |  | $ | 169,288 |
Equipment inventory | 34,984 |  |  | 85,888 |
Prepaid other | 63,634 |  |  | 42,800 |
Retainers and deposits | 26,978 |  |  | 29,478 |
Prepaid federal and Louisiana income taxes | 431,733 |  |  | 419,999 |
Prepaid expenses and other current assets | $ | 650,826 |  |  | $ | 747,453 |

Note 4 — Property and Equipment
As of March 31, 2015 and June 30, 2014 our oil and natural gas properties and other property and equipment consisted of the following:

| March 31, 2015 |  | June 30, 2014
Oil and natural gas properties |  |  |  |  |
Property costs subject to amortization | $ | 51,722,157 |  |  | $ | 47,166,282 |
Less: Accumulated depreciation, depletion, and amortization | (11,372,217 | ) |  | (9,344,212 | )
Unproved properties not subject to amortization | — |  |  | — |
Oil and natural gas properties, net | $ | 40,349,940 |  |  | $ | 37,822,070 |
Other property and equipment |  |  |  |  |
Furniture, fixtures and office equipment, at cost | $ | 288,732 |  |  | $ | 343,178 |
Artificial lift technology equipment, at cost | 330,525 |  |  | 377,943 |
Less: Accumulated depreciation | (310,846 | ) |  | (296,294 | )
Other property and equipment, net | $ | 308,411 |  |  | $ | 424,827 |

During the nine months ended ended March 31, 2015, we incurred $225,883 of costs related to the installation of our artificial lift technology, GARP®, on the remaining two wells of a five-well program for a third-party customer. Under the contract for these installations, we fund the majority of the incremental equipment and installation costs and will receive 25% of the net profits from production, as defined, for as long as the technology remains in the wells. We are depreciating these costs using a method and a life which approximates the timing and amounts of our expected net revenues from the wells. During the nine months ended March 31, 2015, we recorded additional depreciation of $273,301 reflecting the impairment of unrecovered installation costs of artificial lift equipment, net of estimated residual salvage value, which had been removed from three wells of a third-party customer. Artificial lift equipment cost and corresponding accumulated depreciation have both been reduced by the $273,301 impairment.
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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 5 — Other Assets
As of March 31, 2015 and June 30, 2014 our other assets consisted of the following:

| March 31, 2015 |  | June 30, 2014
Trademarks | $ | 43,333 |  |  | $ | 40,928 |
Patent costs | 487,064 |  |  | 305,592 |
Less: Accumulated amortization of patent costs | (39,992 | ) |  | (27,050 | )
Deferred loan costs | 306,740 |  |  | 243,003 |
Less: Accumulated amortization of deferred loan costs | (134,898 | ) |  | (98,421 | )
Other assets, net | $ | 662,247 |  |  | $ | 464,052 |

Note 6 — Accrued Liabilities and Other
As of March 31, 2015 and June 30, 2014 our other current liabilities consisted of the following:

| March 31, 2015 |  | June 30, 2014
Accrued incentive and other compensation | $ | 566,465 |  |  | $ | 1,358,653 |
Accrued restructuring charges | — |  |  | 530,412 |
Officer retirement costs | — |  |  | 288,258 |
Asset retirement obligations due within one year | 10,219 |  |  | 146,703 |
Accrued royalties | 69,344 |  |  | 89,179 |
Accrued franchise taxes | 94,473 |  |  | 87,575 |
Other accrued liabilities | 49,191 |  |  | 57,224 |
Accrued liabilities and other | $ | 789,692 |  |  | $ | 2,558,004 |

Note 7 — Restructuring
On November 1, 2013, we undertook an initiative to refocus our business to GARP® development that resulted in an
adjustment of our workforce with less emphasis on oil and gas operations and greater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of approximately $1,332,186 representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of severance compensation and benefits to be paid during the twelve months ended December 31, 2014. All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges is as follows:

Type of Cost | Balance at December 31, 2013 |  | Payments |  | Adjustment to Cost |  | Balance at December 31, 2014
Salary continuation liability | $ | 615,721 |  |  | $ | (615,721 | ) |  | $ | — |  |  | $ | — |
Incentive compensation costs | 185,525 |  |  | (185,525 | ) |  | — |  |  | — |
Other benefit costs and employer taxes | 154,575 |  |  | (110,144 | ) |  | (44,431 | ) |  | — |
Accrued restructuring charges | $ | 955,821 |  |  | $ | (911,390 | ) |  | $ | (44,431 | ) |  | $ | — |

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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 8 — 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 obligations for the nine months ended March 31, 2015, and for the year ended June 30, 2014:

| Nine Months Ended March 31, 2015 |  | Year Ended June 30, 2014
Asset retirement obligations — beginning of period | $ | 352,215 |  |  | $ | 615,551 |
Liabilities sold | (52,526 | ) |  | (48,273 | )
Liabilities incurred (a) | 564,019 |  |  | — |
Liabilities settled | (137,604 | ) |  | (323,665 | )
Accretion of discount | 23,697 |  |  | 41,626 |
Revision of previous estimates | 9,670 |  |  | 66,976 |
Less obligations due within one year | (10,219 | ) |  | (146,703 | )
Asset retirement obligations — end of period | $ | 749,252 |  |  | $ | 205,512 |

(a) Liabilities incurred during the period relate to our share of the the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.
Note 9— Stockholders’ Equity
Common Stock
Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. During the nine months ended March 31, 2015, the Company declared three quarterly dividends and paid $8,192,989 to its common stockholders.
For the nine months ended March 31, 2015, the Board of Directors authorized the issuance of 144,468 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award. In addition, the Board authorized the issuance of 43,258 shares of restricted common stock to various employees for incentive compensation purposes and issued 25,740 shares of restricted common stock as compensation to the Company's directors. See Note 10 - Stock-Based Incentive Plan.
Series A Cumulative Perpetual Preferred Stock
At March 31, 2015, there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the 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. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, 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 through its Dividend Committee. We paid dividends of $505,726 and $505,726 to holders of our Series A Preferred Stock during the nine months ended March 31, 2015 and 2014, respectively.
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2014, cash dividends on preferred and common stock were treated for tax purposes as a return of capital to our stockholders. Based on our current projections for the fiscal year ending June 30, 2015, we expect preferred dividends will be treated as qualified dividend income and that a portion of our cash dividends on common stock will be treated as a return of capital and the remainder as qualified dividend income. We will make a preliminary determination regar
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Notes to Unaudited Consolidated Condensed Financial Statements
ding the tax treatment of dividends for the current fiscal year when we report this information to recipients. As a result of the difference between our June 30 fiscal year and the calendar year basis of our dividend reporting requirements, it is possible that we will be required to amend these reports when our final taxable income for the fiscal year is determined, as this will potentially affect the tax status of our dividends.
Note 10— 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 under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"). The Plan authorizes the issuance of 6,500,000 shares of common stock and 542,529 shares remain available for grant as of March 31, 2015.
Stock Options
No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods.
The following summary presents information regarding outstanding Stock Options as of March 31, 2015, 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 outstanding at July 1, 2014 | 178,061 |  |  | $ | 2.08 |  |  |  |  |  |
Exercised | (87,000 | ) |  | 1.63 |  |  |  |  |  |
Stock Options outstanding at March 31, 2015 | 91,061 |  |  | 2.50 |  |  | $ | 313,720 |  |  | 1.6
Vested or expected to vest at March 31, 2015 | 91,061 |  |  | 2.50 |  |  | 313,720 |  |  | 1.6
Exercisable at March 31, 2015 | 91,061 |  |  | $ | 2.50 |  |  | $ | 313,720 |  |  | 1.6

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($5.95 as of March 31, 2015) and the Stock Option exercise price of in-the-money Stock Options.
Restricted Stock and Contingent Restricted Stock
Prior to August 28, 2014 all restricted stock grants contained a four-year vesting period based solely on service. Restricted Stock which vests based solely on service is valued at the fair market value on the date of grant and amortized over the service period.
During the nine months ended March 31, 2015, the Company awarded grants of both Restricted Stock and contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were issued on the date of grant, whereas the contingent Restricted Stock will be issued only upon the attainment of specified performance-based or market-based vesting provisions.
Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company upon vesting. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the four- year term. As of March 31, 2015, the Company does not consider the vesting of these performance-based grants to be probable and no compensation expense has been recognized.
Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting
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Notes to Unaudited Consolidated Condensed Financial Statements
period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Fair values for these market-based awards ranged from $4.26 to $8.40 with expected vesting periods of 3.30 to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.
The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2015:

| Number of Restricted Shares |  | Weighted Average Grant-Date Fair Value |  | Unamortized Compensation Expense at March 31, 2015 (1) |  | Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014 | 140,067 |  |  | $ | 8.70 |  |  |  |  |
Service-based awards granted | 100,910 |  |  | 9.53 |  |  |  |  |
Performance-based awards granted | 76,642 |  |  | 10.05 |  |  |  |  |
Market-based awards granted | 35,914 |  |  | 7.59 |  |  |  |  |
Vested | (77,920 | ) |  | 8.48 |  |  |  |  |
Forfeited | — |  |  | — |  |  |  |  |
Unvested at March 31, 2015 | 275,613 |  |  | $ | 9.30 |  |  | $ | 1,528,996 |  |  | 2.5

(1) Excludes $770,252 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.
The following table summarizes contingent Restricted Stock activity:

| Number of Restricted Stock Units |  | Weighted Average Grant-Date Fair Value |  | Unamortized Compensation Expense at March 31, 2015 (1) |  | Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014 | — |  |  | — |  |  |  |  |
Performance-based awards granted | 38,325 |  |  | $ | 10.05 |  |  |  |  |
Market-based awards granted | 17,961 |  |  | 4.26 |  |  |  |  |
Unvested at March 31, 2015 | 56,286 |  |  | $ | 8.20 |  |  | $ | 62,787 |  |  | 2.7

(1) Excludes $385,166 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.
Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the three months ended March 31, 2015 and 2014 was $242,835 and $444,981, respectively. Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the nine months ended March 31, 2015 and 2014 was $731,192 and $1,134,841, respectively. For the nine months ended March 31, 2015, this expense includes $15,328 for cash dividends paid on unvested, "not probable" performance-based awards which are not being amortized to expense. Recipients are not required to return dividend payments to the Company if the awarded Restricted Stock never vests. See Note 7 – Restructuring, for stock compensation included in Restructuring Charges recorded at December 31, 2014.
Note 11 — 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:
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Notes to Unaudited Consolidated Condensed Financial Statements
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 12 — Income Taxes
We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.
There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the nine months ended March 31, 2015. 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, 2010 through June 30, 2014.
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.
Based on the carryback of tax losses resulting from the exercise of stock options and incentive warrants in fiscal 2014, we filed a request for refund of cash taxes paid in Louisiana for the previous three fiscal years totaling approximately $1.5 million. This refund request is subject to final approval by the Louisiana tax authorities and we cannot be certain of the timing or amount of the ultimate recovery. This carryback will utilize approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes, with $5.1 million of tax loss carryforwards remaining for Louisiana tax purposes. When received, this refund will not affect our tax provision for financial reporting purposes. We will recognize the benefit as an increase in additional paid-in capital.
We recognized income tax expense of $2,118,218 and $1,148,155 for the nine months ended March 31, 2015 and 2014, respectively, with corresponding effective rates of 40.6% and 36.6%.
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Notes to Unaudited Consolidated Condensed Financial Statements
Note 13 — Net Income Per Share
The following table sets forth the computation of basic and diluted income (loss) per share:

| Three Months Ended March 31, |  | Nine Months Ended March 31,
| 2015 |  | 2014 |  | 2015 |  | 2014
Numerator |  |  |  |  |  |  |  |  |  |  |
Net income available to common shareholders | $ | 566,011 |  |  | $ | 755,125 |  |  | $ | 2,597,788 |  |  | $ | 1,481,542 |
Denominator |  |  |  |  |  |  |  |  |  |  |
Weighted average number of common shares — Basic | 32,861,001 |  |  | 32,358,163 |  |  | 32,789,157 |  |  | 30,328,344 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |  |  |
Contingent restricted stock grants | 5,954 |  |  | — |  |  | 3,568 |  |  | — |
Stock options | 91,263 |  |  | 373,886 |  |  | 117,256 |  |  | 2,175,116 |
Weighted average number of common shares and dilutive potential common shares used in diluted EPS | 32,958,218 |  |  | 32,732,049 |  |  | 32,909,981 |  |  | 32,503,460 |
Net income per common share — Basic | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.05 |
Net income per common share — Diluted | $ | 0.02 |  |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.05 |

Outstanding potentially dilutive securities as of March 31, 2015 were as follows:

Outstanding Potential Dilutive Securities | Weighted Average Exercise Price |  | At March 31, 2015
Contingent Restricted Stock grants | — |  |  | 56,286 |
Stock Options | $ | 2.50 |  |  | 91,061 |
| $ | 1.55 |  |  | 147,347 |

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

Outstanding Potential Dilutive Securities | Weighted Average Exercise Price |  | At March 31, 2014
Stock options | $ | 2.02 |  |  | 228,061 |

Note 14 — Unsecured Revolving Credit Agreement
On February 29, 2012, EPM entered into a credit agreement (the “Credit Agreement”) with Texas Capital Bank, N.A. (the “Lender”). The Credit Agreement provides us with a revolving credit facility (the “facility”) in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000. A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit.
The facility is unsecured and has a term of four years, expiring on February 29, 2016. Our subsidiaries guarantee EPM’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 our reserve reports. Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender’s credit approval process, and are also limited to 25% of the value of our oil and gas properties, as defined in the Credit Agreement.
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
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Notes to Unaudited Consolidated Condensed Financial Statements
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. The maximum term of letters of credit 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 $50,000 in loan costs incurred 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 1 X 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, if any, to be immediately due and payable.
As of March 31, 2015, 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, and we are in compliance with all the covenants of the Credit Agreement. During May 2014, the Credit Agreement was amended to permit the payment of cash dividends on common stock if no borrowings are outstanding at the time of such payment.
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. The unamortized balance in debt issuance costs related to the Credit Agreement was $44,570 as of March 31, 2015. The Company is in discussions with the Lender to replace the unsecured Credit Agreement with an expanded secured facility. As of March 31, 2015, the Company had incurred approximately $127,272 in legal and title costs related to this proposed agreement, which are also capitalized in Other Assets.
Note 15 — 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 jurisdictions 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.
The Company and its wholly-owned subsidiary NGS Sub Corp. are defendants in a lawsuit brought by John C. McCarthy et al 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. The plaintiffs are seeking cancellation of the transaction and monetary damages. On March 29, 2012, the Fifth District Court dismissed the case against the Company and NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiffs’ 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 again filed an appeal in November 2013. In October 2014, the appellate court reversed the district court. We subsequently filed for a rehearing which was denied. We now have filed an Application for Writ of Review in the Louisiana Supreme Court in which we have asked the Louisiana Supreme Court to reverse the appellate court and reinstate the trial court judgment dismissing plaintiffs’ case. Amicus Curiae Briefs have been filed in support of the writ application by the Louisiana Oil & Gas Association, the Louisiana Mid-Continent Oil and Gas Association and the American Association of Professional Landmen. The Application for Writ of Review was unanimously accepted by the Louisiana Supreme Court, our brief and supporting Amicus Curiae Briefs have been filed and oral arguments are expected to be scheduled in the near term.
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Notes to Unaudited Consolidated Condensed Financial Statements
As previously reported, on August 23, 2012, we and our wholly-owned subsidiary, NGS Sub Corp., and Robert S. Herlin, our Chief Executive Officer, 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 alleged primarily that we (defendants) wrongfully purchased the plaintiffs’ 4.8119% 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 enhanced oil recovery. The plaintiffs were seeking rescission of the assignment of the overriding royalty interest and monetary damages. We believed that the claims were without merit and not timely, and we vigorously defended against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the plaintiffs to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the plaintiffs' 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 the nondismissal of the remaining claims, which was denied. The Court entered a Scheduling Order setting trial of the case for the week of June 15, 2015. Subsequent to depositions of the plaintiffs, in late March 2015, in the United States District Court for the Western District of Louisiana Monroe Division, a joint motion to dismiss with prejudice was entered into by all parties in the lawsuit and the judge signed the judgment of dismissal with prejudice. Further, no compensation or other consideration was paid or provided to the plaintiffs by any of the defendants other than an agreement by us not to sue for malicious prosecution or defamation, or seek sanctions, and the plaintiffs agreed to relinquish any and all claims to the 4.8119% overriding royalty interest in the Delhi Unit.
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 (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi Field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We also alleged that Denbury’s gross negligence caused certain environmental damage to the unit. Specifically, we allege that Denbury failed to properly conduct CO2 injection activities. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims, including the assertion that we owe Denbury additional revenue interests pursuant to the 2006 agreements and that our transfers of the reversionary interests from our wholly owned subsidiary to our parent corporation and subsequently to another wholly-owned subsidiary were not timely noticed to Denbury. We subsequently amended and expanded our claims. The Company disagrees with, and is vigorously defending against, Denbury's counterclaims.
On January 26, 2015, Denbury notified us it had withheld and suspended 2.891545% of our overriding royalty revenue interest in the field for the months of November and December 2014. This unilateral suspension of a portion of our overriding royalties by the operator was made without consultation with the Company and, we believe, was without legal basis. On February 26, 2015, we and Denbury executed an agreement under which Denbury agreed to reverse the previously disclosed suspension of our overriding royalty interest revenues and release to Evolution amounts previously suspended totaling approximately $712,000. Denbury further agreed not to suspend any future revenues attributable to any of our revenue interests, except under limited circumstances. This agreement did not settle any of the outstanding litigation matters with Denbury, including their counterclaim related to the net revenue interest conveyed in the 2006 Purchase and Sale Agreement.
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 and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed Mr. Brooks' claims against NGS Sub Corp. We have denied and are vigorously defending all claims by Mr. Hawkins and do not consider the claims material to the Company.
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Notes to Unaudited Consolidated Condensed Financial Statements
Lease Commitments. We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of March 31, 2015 under this operating lease are as follows:

For the twelve months ended March 31, |
2016 | $ | 159,011 |
2017 | 53,004 |
Total | $ | 212,015 |

Rent expense for the three months ended March 31, 2015 and 2014 was $43,776 and $44,473, respectively. Rent expense for the nine months ended March 31, 2015 and 2014 was $131,327 and $131,151, respectively.
Employment Contracts. We have entered into employment agreements with two of the Company's senior executives. The employment contracts provide for severance payments in the event of termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, as defined. The agreements provide for the payment of base pay and certain medical and disability benefits for periods ranging from six months to one year after termination. The total contingent obligation under the employment contracts as of March 31, 2015 is approximately $473,000.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2014 (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 2014 Annual Report on Form 10-K for the year ended June 30, 2014 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 and its wholly owned subsidiaries.
Executive Overview
General
We are engaged primarily in the development of incremental oil and gas reserves within known oil and gas resources for our stockholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our stockholders, and a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership in our common stock.
Our strategy is to grow the value of our Delhi asset to maximize the value realized by our stockholders while commercializing our patented GARP® artificial lift technology for recovering incremental oil and gas reserves in mature fields.
We are currently funding our fiscal 2015 capital program from working capital and net cash flows from our properties.
Highlights for our Third Quarter of Fiscal 2015 and Project Update
"Q3-15" & "current quarter" refer to the three months ended March 31, 2015, the Company's 3 rd quarter of fiscal 2015.
"Q2-15" & "prior quarter" refer to the three months ended December 31, 2014, the Company's 2 nd quarter of fiscal 2015.
"Q3-14" & "year-ago quarter" refer to the three months ended March 31, 2014, the Company's 3 rd quarter of fiscal 2014.
Operations

• | For Q3-15, the Company earned $0.6 million of net income, or $0.02 per diluted common share, a 25% decrease from the year-ago quarter and a 47% decrease from the prior quarter. The significant decline in oil prices is the primary driver for lower net income compared to both the year-ago quarter and the prior quarter, despite increased sales volumes as a result of our reversionary working interest at Delhi.

• | Current quarter revenues were $7.1 million, a 63% increase from the year-ago quarter and an 8% decrease from the prior quarter. The increase from the year-ago quarter was due to net revenues associated with the reversion

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of our working interest ownership in the Delhi field in November 2014, offset by significantly lower realized oil prices due to current market conditions. The decrease from prior quarter is due to lower realized oil prices under current market conditions, offset by increased oil volumes at Delhi for three months versus only two months of working interest sales based on the November 1, 2014 effective date of our reversionary working interest.

• | Our Delhi production averaged 1,640 net barrels of oil per day (“BOPD”), a 259% increase from the year-ago quarter, and a 38% increase from the prior quarter. The increase in volumes from the year-ago quarter is due to the additional volumes associated with the working interest ownership in the Delhi field. The increase in volumes from prior quarter is due to three months of working interest production versus two months, post payout effective as of November 1, 2014. Gross production in the field averaged 6,203 BOPD during the current quarter, an increase of 5% over the prior quarter gross rate of 5,892 BOPD.

• | Delhi average realized crude oil prices received in Q3-15 decreased 53% to approximately $48 per barrel from approximately $102 per barrel in the year-ago quarter, and decreased 32% from approximately $70 per barrel in the prior quarter. Delhi oil pricing is based on Louisiana Light Sweet index, which continues to be valued at a premium compared to West Texas Intermediate.

• | We remain debt-free and distributed $1.6 million of cash dividends to our common stockholders during the current quarter.

Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2014.
Delhi Field - Enhanced Oil Recovery Project
Gross production at Delhi in the third quarter of fiscal 2015 averaged 6,203 BOPD, a increase of 1% from the year-ago quarter, and a 5% increase from the prior quarter. Net production averaged 1,640 BOPD, a 259% increase from the year-ago quarter, and a 38% increase from the prior quarter. Gross production continues to be positively impacted by a replacement well that was redrilled and placed into production in January 2015.
In the quarter ending March 31, 2015, our net share of the joint interest billed lease operating expenses was approximately $2.9 million, of which $1.6 million is related to CO 2 purchases and transportation expenses. Under our contract with the operator, purchased CO 2 is priced at 1% of the oil price in the field per thousand cubic feet (“Mcf”) plus transportation costs of $0.20 per Mcf. Total average CO 2 costs per month are down 36% from the prior quarter monthly as result of both lower oil prices and lower purchased CO 2 volumes in the quarter. Purchased CO 2 volumes in the prior quarter were significantly higher than the expected rates going forward of 90,000 to 95,000 Mcf per day. On a total BOE basis, average CO 2 costs were down 29% from $15.33 BOE in the prior quarter to $10.82 BOE, primarily due to increased working interest volumes and lower realized oil prices in the current quarter. Our purchased CO 2 costs are directly correlated with realized oil prices.
In late February 2015, we signed an authorization for expenditure for construction of a natural gas liquids ("NGL") recovery plant in the Delhi field, which will extract both NGL and methane from the field. In addition to the value of these hydrocarbon products, according to the operator, the increased purity of the CO 2 stream re-injected into the field should result in significant operational benefits to the CO 2 flood and potentially increase oil production from existing wells and/or accelerated recovery of oil reserves. The NGL plant has an estimated gross cost of $103 million ($24.6 million net to the Company) projected to be expended through the summer of 2016. Recovered methane will be utilized to generate much, if not all, of the electricity for the operation of the gas plant and other CO 2 field operations. This will substantially reduce operating costs for both the existing field operation and the new plant operating costs. The plant is projected by the operator to produce up to approximately 2,000 barrels of NGL's per day when in full operation and NGL volumes potentially may be higher based on performance and yield.
On January 26, 2015, Denbury notified us it had withheld and suspended 2.891545% of our overriding royalty revenue interest in the field for the months of November and December 2014, as previously disclosed. This unilateral suspension of a portion of our overriding royalties by the operator was made without consultation with the Company and, we believe, was without legal basis. On February 26, 2015, we entered into an agreement under which Denbury agreed to reverse the previously disclosed suspension of our overriding royalty interest revenues and release to Evolution amounts previously suspended totaling approximately $712,000. Denbury further agreed not to suspend any future revenues attributable to any of our revenue interests, except under very limited circumstances. This agreement does not settle any of the outstanding litigation
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matters with Denbury, including their counterclaim related to the net revenue interest conveyed in the 2006 Purchase and Sale Agreement.
GARP® - Artificial Lift Technology
During the current quarter, the GARP® installation in the Appelt #1H well, that had been shut-in for over a year due to solids production, was worked over to install better solids handling capacity and thereby restored to producing status at the previous rate of approximately 10 barrels of oil per day. The Selected Lands #2 well was also restored to production in the quarter. Lastly, the Philip #1 well was temporarily abandoned after unsuccessful workovers to permanently remove solids from sticking to the pump. These workovers were included in our operating costs for the quarter.
We continue to work diligently to advance the development of the GARP® technology and expect to file three GARP® patents and one provisional GARP® patent in the coming weeks to solve specific needs identified by customers.
Recent GARP® marketing and business development efforts have secured three master service agreements, including with one major, one super-independent and one large independent oil producer and a fourth agreement is pending.
Approval as a vendor to provide oil field services does not guarantee an agreement to install GARP® technology, which is governed by a separate agreement.
Liquidity and Capital Resources
We had $20.4 million and $23.9 million in cash and cash equivalents at March 31, 2015 and June 30, 2014, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility at period end.
During the nine months ended March 31, 2015, we financed our operations with cash generated from operations and cash on hand. At March 31, 2015, our working capital was $18.4 million, compared to working capital of $23.3 million at June 30, 2014. The $4.9 million working capital decrease is primarily due to a $4.1 million increase in accounts payable reflecting post-reversion Delhi field operating expenses and capital expenditures together with $3.5 million of lower cash, partially offset by $1.6 million of lower accrued liabilities principally attributable to incentive compensation, restructuring and officer retirement accrual declines and $1.0 million of increased accounts receivable primarily due to the interest reversion.
Cash Flows from Operating Activities
For the nine months ended March 31, 2015, cash flows provided by operating activities were $6.6 million, which included $0.4 million used by other working capital items. Of the $7.0 million provided before other working capital changes, approximately $3.1 million was due to net income, and approximately $3.9 million was attributable to non-cash expenses and settlements of asset retirement obligations.
For the nine months ended March 31, 2014, cash flows provided by operating activities were $5.7 million, reflecting $5.4 million provided by operations before $0.2 million provided by other working capital changes. Of the $5.4 million provided before other working capital changes, $2.0 million was due to net income, which includes $1.3 million of restructuring and $0.6 million of retirement obligation charges, and $3.4 million was attributable to non-cash expenses.
Cash Flows from Investing Activities
Investing activities for the nine months ended March 31, 2015 used $2.5 million of cash, consisting primarily of capital expenditures of approximately $2.4 million for Delhi field, $0.3 million for artificial lift technology together with $0.2 million of other assets comprised primarily of GARP® patent costs, partially offset by $0.4 million of proceeds received for the sale of properties in the Mississippi Lime project in October 2014.
Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2014 was $1.0 million. Development activities were about equally divided among GARP® wells in Giddings and the Sneath and Hendrickson wells completed in the Mississippi Lime during the prior year. We received approximately $542,000 of proceeds from asset sales, including $400,000 from the sale of our South Texas properties, and $250,000 of cash from the maturity of a certificate of deposit.
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Cash Flows from Financing Activities
In the nine months ended March 31, 2015, we used $7.6 million in cash for financing activities principally consisting of cash outflows of $8.2 million for common stock dividend payments and $0.5 million for preferred dividend payments, offset partially by $1.1 million of cash provided by tax benefits related to stock-based compensation.
In the nine months ended March 31, 2014, we used $5.3 million in cash for financing activities, including cash inflows of $3.2 million from stock option exercise proceeds and $0.1 million of windfall tax benefits, offset by cash outflows of $6.5 million for common dividends, $0.5 million for preferred dividends and $1.6 million for stock exchanged for payroll tax liabilities and exercise price payments related to incentive stock warrant and stock option exercises and restricted stock vestings.
Capital Budget
Delhi Field
With the operator's determination that reversion of our 23.9% working interest and 19.036% net revenue interest in Delhi occurred effective November 1, 2014, we began funding our share of capital expenditures in the field as of that date going forward. From reversion through March 31, 2015, our net share of the joint interest billed capital expenditures was approximately $4.4 million. Capital expenditures primarily consisted of redrilling a producer well, testing and strengthening of well bore integrity, and drilling and completion of monitoring wells.
Projected capital expenditures over the next two fiscal years are currently expected to total approximately $25-35 million net to our working interest. The timing and actual amount of this spending is primarily dependent on the pace of project development by the operator and project economics based on current and forward looking oil prices. Of this total, approximately $24.6 million is for the gas processing plant and the balance is for continued development of the CO 2 project into the eastern half of the field. We expect these costs to be incurred over portions of the next two fiscal years, although these development plans are subject to review and deferral. Total spending based on proved reserves in the reserve report, net to our interest, is currently forecast to be up to approximately $50 million over the next four years, which includes the projects above plus further expansion of the CO 2 flood patterns.
GARP® - Artificial Lift Technology
Based on our current marketing and business plans, we expect that our capital requirements for artificial lift technology operations will be relatively minor over the next fiscal year.
Liquidity Outlook
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. To date, our Board of Directors have followed a policy of not hedging future commodity sales due to our having no outstanding debt. As a result, our future revenues, cash flow, profitability, access to capital and future rate of growth is heavily influenced by the prices received for our production. Liquidity could also be affected by any litigation outcome, positive or negative.
Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Our preference is to remain debt free absent any strategic move, but we have access to an unsecured revolving line of credit and have plans to convert this line into a senior secured facility with significantly higher borrowing capacity with an extended term, to use as needed. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs or acquisition opportunities.
Payment of free cash flow in excess of our operating and capital requirements through cash dividends on our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate. The Board of Directors and management instituted this strategy over a year ago due to our belief that high commodity prices at the time limited attractive oil and gas investment opportunities. However, due to the potential to pursue other opportunities at discounted prices during the current industry downturn combined with the anticipated cost of building and installing the Delhi recycle gas processing plant during calendar years 2015 and 2016, the Dividend Committee and the Board of Directors believed it was prudent to adjust the current dividend rate from $0.40 per share annually to $0.20 per share annually, effective in the quarter ending March 31, 2015. The reduction in the dividend rate will allow the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield.
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Results of Operations
Three month periods ended March 31, 2015 and 2014
The following table sets forth certain financial information with respect to our oil and natural gas operations:

| Three Months Ended March 31, |  |  |  |
| 2015 |  | 2014 |  | Variance |  | Variance %
Delhi field: |  |  |  |  |  |  |
Crude oil revenues | $ | 7,039,868 |  |  | $ | 4,185,156 |  |  | $ | 2,854,712 |  |  | 68.2 | %
Crude oil volumes (Bbl) | 147,621 |  |  | 41,137 |  |  | 106,484 |  |  | 258.9 | %
Average price per Bbl | $ | 47.69 |  |  | $ | 101.74 |  |  | $ | (54.05 | ) |  | (53.1 | )%
Delhi field production costs | $ | 2,932,946 |  |  | $ | — |  |  | $ | 2,932,946 |  |  | — | %
Delhi field production costs per BOE | $ | 19.87 |  |  | $ | — |  |  | $ | 19.87 |  |  | — | %
Artificial lift technology: |  |  |  |  |  |  |
Crude oil revenues | $ | 12,695 |  |  | $ | 95,031 |  |  | $ | (82,336 | ) |  | (86.6 | )%
NGL revenues | 1,352 |  |  | 29,360 |  |  | (28,008 | ) |  | (95.4 | )%
Natural gas revenues | 529 |  |  | 26,661 |  |  | (26,132 | ) |  | (98.0 | )%
Service revenues | 10,245 |  |  | — |  |  | 10,245 |  |  | — | %
Total revenues | $ | 24,821 |  |  | $ | 151,052 |  |  | $ | (126,231 | ) |  | (83.6 | )%
Crude oil volumes (Bbl) | 285 |  |  | 966 |  |  | (681 | ) |  | (70.5 | )%
NGL volumes (Bbl) | 73 |  |  | 756 |  |  | (683 | ) |  | (90.3 | )%
Natural gas volumes (Mcf) | 204 |  |  | 5,453 |  |  | (5,249 | ) |  | (96.3 | )%
Equivalent volumes (BOE) | 392 |  |  | 2,631 |  |  | (2,239 | ) |  | (85.1 | )%
Crude oil price per Bbl | $ | 44.54 |  |  | $ | 98.38 |  |  | $ | (53.84 | ) |  | (54.7 | )%
NGL price per Bbl | 18.52 |  |  | 38.84 |  |  | (20.32 | ) |  | (52.3 | )%
Natural gas price per Mcf | $ | 2.59 |  |  | 4.89 |  |  | (2.30 | ) |  | (47.0 | )%
Equivalent price per BOE | $ | 37.18 |  |  | $ | 57.41 |  |  | $ | (20.23 | ) |  | (35.2 | )%
Artificial lift production costs (a) | $ | 267,906 |  |  | $ | 209,742 |  |  | $ | 58,164 |  |  | 27.7 | %
Artificial lift production costs per BOE | $ | 683.43 |  |  | $ | 79.72 |  |  | $ | 603.71 |  |  | 757.3 | %
Other properties: |  |  |  |  |  |  |
Revenues | $ | — |  |  | $ | 798 |  |  | $ | (798 | ) |  | (100.0 | )%
Equivalent volumes (BOE) | — |  |  | 26 |  |  | (26 | ) |  | (100.0 | )%
Equivalent price per BOE | $ | — |  |  | $ | 30.69 |  |  | $ | (30.69 | ) |  | (100.0 | )%
Production costs | $ | 639 |  |  | $ | 143,887 |  |  | $ | (143,248 | ) |  | (99.6 | )%
Production costs per BOE | $ | — |  |  | $ | 5,534.12 |  |  | $ | (5,534.12 | ) |  | (100.0 | )%
Combined: |  |  |  |  |  |  |
Oil and gas DD&A (b) | $ | 1,099,737 |  |  | $ | 302,083 |  |  | $ | 797,654 |  |  | 264.1 | %
Oil and gas DD&A per BOE | $ | 7.43 |  |  | $ | 6.90 |  |  | $ | 0.53 |  |  | 7.7 | %

(a) Includes workover costs of approximately $252,000 and $123,000, for the three months ended March 31, 2015 and 2014, respectively, that were primarily utilized to restore production in the Appelt #1H and Selected Lands #2 wells.
(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $38,765 and $9,732, for the three months ended March 31, 2015 and 2014, respectively.
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Net Income Available to Common Stockholders. For the three months ended March 31, 2015, we generated net income to common shareholders of $0.6 million, or $0.02 per diluted share, on total revenues of $7.1 million. This compares to a net income of $.08 million, or $0.02 per diluted share, on total revenues of $4.3 million for the year-ago quarter. The $0.2 million earnings decrease is primarily due to increased production costs partially offset by higher revenues. The $0.8 million reduction achieved in general and administrative expense was offset by an increase in non-cash DD&A expense. The components of net income are explained in greater detail below.
Delhi Field. Revenues increased 68% to $7.0 million as a result of a 259% increase in production volumes from the year-ago quarter primarily due to our November 1, 2014 reversionary working interest, partially offset by a 53% decline in realized crude oil prices from $101.74 per barrel to $47.69 per barrel. Gross production of 6,203 BOPD was essentially flat compared to the year-ago quarter. Production costs for the current quarter were $2.9 million, of which $1.6 million was for CO 2 purchases and transportation expenses, compared to no production costs in the year-ago quarter as those revenues were derived solely from our mineral and overriding royalty interests, which bore no operating expenses. Under our contract with the operator, purchased CO 2 is priced at 1% of the oil price in the field per Mcf plus $0.20 per Mcf transportation costs. For the current quarter total production costs were $27.60 per working interest BOE, which includes $15.03 per BOE for CO 2 purchase costs.
Artificial Lift Technology. Revenues decreased 84% to $25,000 reflecting a 85% volume decrease, primarily as a result of workovers on the Philip DL #1, Appelt #1H and Selected Lands #2 wells, together with a 35% decrease in the realized price per BOE, from $57.41 to $37.18 BOE. In the current quarter, we recorded $10,245 of service fee revenue from the GARP® installations for a third-party customer. These wells have not contributed meaningful net profits to the Company in the current quarter due to low commodity prices, poor netback contracts for gas processing and higher workover costs. Artificial lift production costs were $268,000 for the current quarter, a 28% increase from $210,000 for the year-ago quarter, and includes $252,000 in costs for the aforementioned workovers, which were necessary in recovering proved reserves by restoring significant production in the Appelt and Selected Lands #2 wells.
Other Properties. We have divested all of our non-core oil and gas properties, therefore there are no revenues to report in the current quarter. The prior year-ago quarter had slight revenue of $798. The production costs from the year-ago quarter were high as a result of high water production in our Mississippi Lime property interest which we sold in the prior quarter.
General and Administrative Expenses (“G&A”). G&A expenses decreased $0.8 million, or 36%, to $1.5 million for the three months ended March 31, 2015 from $2.3 million in the year-ago quarter, primarily due to a $0.6 million decrease in compensation and benefits due to the fiscal 2014 non-recurring charge for the retirement of our vice president and chief financial officer together with $0.3 million decline in accrued incentive compensation, partially offset by $102,000 of higher legal expense, which reflected $0.3 million of current quarter litigation costs.
Depletion & Amortization Expense (“DD&A”). DD&A increased $827,000, or 265% to $1.1 million for the current quarter compared to $312,000 for the year-ago quarter principally because of higher amortization of our full cost oil and gas property cost pool. Full cost pool amortization increased to $1.1 million from $302,000 in the year-ago quarter due to 238% higher volume of 148,013 BOE as a result of the reversion of our working interest in Delhi field together with a higher rate per BOE ($7.43 in the current quarter versus $6.90 per BOE in the year-ago quarter). Compared to the year-ago quarter, reserves were lower as natural gas proved reserves to be recovered from the recycle stream by the planned Delhi gas plant are now to be used to generate power for the Delhi field and not sold to third party customers. The offset to the lower reserves is a lower projected lease operating expense at Delhi. Additionally, there was some decline in proved reserves at June 30, 2014 from the previous fiscal year-end due to lower injection pressure and development deferrals. Further, our future capital expenditures related to the NGL plant to be constructed over the next fifteen months are higher, offset by a lower operating expense of the plant, due to the working interest owners bearing all of the plant cost instead of the plant contract operator bearing approximately 30% of the plant cost.
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Nine month periods ended March 31, 2015 and 2014
The following table sets forth certain financial information with respect to our oil and natural gas operations:

| Nine Months Ended March 31, |  |  |  |
| 2015 |  | 2014 |  | Variance |  | Variance %
Delhi field: |  |  |  |  |  |  |
Crude oil revenues | $ | 18,553,301 |  |  | $ | 12,745,203 |  |  | $ | 5,808,098 |  |  | 45.6 | %
Crude oil volumes (Bbl) | 295,915 |  |  | 124,089 |  |  | 171,826 |  |  | 138.5 | %
Average price per Bbl | $ | 62.70 |  |  | $ | 102.71 |  |  | $ | (40.01 | ) |  | (39.0 | )%
Delhi field production costs | $ | 5,750,812 |  |  | $ | — |  |  | $ | 5,750,812 |  |  | — | %
Delhi field production costs per BOE | $ | 19.43 |  |  | $ | — |  |  | $ | 19.43 |  |  | — | %
Artificial lift technology: |  |  |  |  |  |  |
Crude oil revenues | $ | 129,714 |  |  | $ | 340,230 |  |  | $ | (210,516 | ) |  | (61.9 | )%
NGL revenues | 34,607 |  |  | 77,986 |  |  | (43,379 | ) |  | (55.6 | )%
Natural gas revenues | 23,446 |  |  | 64,821 |  |  | (41,375 | ) |  | (63.8 | )%
Service revenues | 16,146 |  |  | — |  |  | 16,146 |  |  | — | %
Total revenues | $ | 203,913 |  |  | $ | 483,037 |  |  | $ | (279,124 | ) |  | (57.8 | )%
Crude oil volumes (Bbl) | 1,620 |  |  | 3,383 |  |  | (1,763 | ) |  | (52.1 | )%
NGL volumes (Bbl) | 1,228 |  |  | 2,358 |  |  | (1,130 | ) |  | (47.9 | )%
Natural gas volumes (Mcf) | 7,056 |  |  | 17,932 |  |  | (10,876 | ) |  | (60.7 | )%
Equivalent volumes (BOE) | 4,024 |  |  | 8,730 |  |  | (4,706 | ) |  | (53.9 | )%
Crude oil price per Bbl | $ | 80.07 |  |  | $ | 100.57 |  |  | $ | (20.50 | ) |  | (20.4 | )%
NGL price per Bbl | 28.18 |  |  | 33.07 |  |  | (4.89 | ) |  | (14.8 | )%
Natural gas price per Mcf | 3.32 |  |  | 3.61 |  |  | (0.29 | ) |  | (8.0 | )%
Equivalent price per BOE | $ | 46.66 |  |  | $ | 55.33 |  |  | $ | (8.67 | ) |  | (15.7 | )%
Artificial lift production costs (a) | $ | 656,819 |  |  | $ | 526,712 |  |  | $ | 130,107 |  |  | 24.7 | %
Artificial lift production costs per BOE | $ | 163.23 |  |  | $ | 60.33 |  |  | $ | 102.90 |  |  | 170.6 | %
Other properties: |  |  |  |  |  |  |
Revenues | $ | 20,369 |  |  | $ | 134,754 |  |  | $ | (114,385 | ) |  | (84.9 | )%
Equivalent volumes (BOE) | 285 |  |  | 1,516 |  |  | (1,231 | ) |  | (81.2 | )%
Equivalent price per BOE | $ | 71.47 |  |  | $ | 88.89 |  |  | $ | (17.42 | ) |  | (19.6 | )%
Production costs | $ | 98,051 |  |  | $ | 481,697 |  |  | $ | (383,646 | ) |  | (79.6 | )%
Production costs per BOE | $ | 344.04 |  |  | $ | 317.74 |  |  | $ | 26.30 |  |  | 8.3 | %
Combined: |  |  |  |  |  |  |
Oil and gas DD&A (b) | $ | 2,061,440 |  |  | $ | 922,781 |  |  | $ | 1,138,659 |  |  | 123.4 | %
Oil and gas DD&A per BOE | $ | 6.87 |  |  | $ | 6.87 |  |  | $ | — |  |  | — | %

(a) Includes workover costs of approximately $535,000 and $200,000, for the nine months ended March 31, 2015 and 2014, respectively.
(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $364,169 and $25,875, for the nine months ended March 31, 2015 and 2014, respectively.
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Net Income Available to Common Stockholders. For the nine months ended March 31, 2015, we generated net income to common stockholders of $2.6 million, or $0.08 per diluted share, on total revenues of $18.8 million. This compares to net income of $1.5 million, or $0.05 per diluted share, on total revenues of $13.4 million for the corresponding year-ago period. As higher revenue was mostly offset by increased production costs due to much lower oil prices, the earnings increase is primarily due to expense decreases of $2.3 million for G&A expense and $1.3 million for restructuring charges, partially offset by $1.5 million of higher DD&A expense. Additional details of the components of net income are explained in greater detail below.
Delhi Field. Revenues increased 46% to $18.6 million as a result of a 139% increase in production volumes from the corresponding year-ago period primarily due to the November 2014 reversion of our working interest, partially offset by a 39% decline in realized crude oil prices, from $102.71 per barrel to $62.70 per barrel. Gross production of decreased 3% to 5,942 BOPD compared to 6,116 BOPD for the year-ago period. Production costs for the nine months ended March 31, 2015 were $5.8 million, of which $3.3 million was for CO 2 purchases and transportation expenses, compared to no production costs in the corresponding year-ago period as those revenues were derived solely from our mineral and overriding royalty interests, which bear no operating expenses. Under our contract with the operator, purchased CO 2 is priced at 1% of the oil price in the field per Mcf plus $0.20 per Mcf transportation costs. Accordingly, such costs will be reduced in the future if oil prices remain at lower price levels. From our November 1, 2014 working interest reversion to March 31, 2015, total production costs were $32.80 per working interest BOE which includes CO 2 costs of $18.66 per working interest BOE.
Artificial Lift Technology. Revenues decreased 58% to $204,000 reflecting a 54% volume decrease, primarily as a result of a workover on the Philip DL #1, together with a 16% decrease in the realized price per BOE, from $55.33 per barrel to $46.66 per barrel. We recorded $16,146 of service revenue from GARP® installations for a third-party customer. These wells did not contribute meaningful net profits to the Company in the nine months ended March 31, 2015. Artificial lift production costs were $657,000, which included $535,000 in workover costs, which were necessary in recovering proved reserves by restoring production in two key wells operated by us, the Appelt and the Selected Lands #2.
Other Properties. The Company began divesting its non-core oil and gas properties in fiscal 2013, and revenues from these properties have correspondingly decreased to $20,000 compared to $135,000 in the corresponding year-ago period. The production costs from the year-ago period were high as a result of workover costs in South Texas and high water production in the Mississippi Lime. We completed our divestiture process in the prior quarter with the sale of the remaining interests in our Mississippi Lime properties.
General and Administrative Expenses (“G&A”). G&A expenses decreased $2.3 million, or 33%, to $4.6 million during the nine months ended March 31, 2015 from $6.9 million in the corresponding year-ago period primarily due to fiscal 2014 non-recurring charges of $0.8 million related to stock option exercises and $0.6 million related to the retirement of our vice president and chief financial officer, a $0.5 million decrease in personnel-related costs as a result of our December 2013 restructuring, and a $0.5 million decline in accrued incentive compensation, partially offset by $0.2 million of higher legal expense, impacted by $0.5 million of fiscal 2015 litigation costs. This fiscal 2014 restructuring charge of $1.3 million consisted of $0.9 million of termination benefits and $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees. See Note 7 - Restructuring.
Depletion & Amortization Expense (“DD&A”). DD&A increased $1.5 million, or 156%, to $2.4 million for the nine months ended March 31, 2015 from $0.9 million for the corresponding year-ago period. Amortization of our full cost oil and gas property cost pool increased by $1.1 million, or 123% primarily due to higher volume generated by the reversionary working interest. For the nine months ended March 31, 2015, our rate of $6.87 per BOE was flat compared to the corresponding year-ago period. Depreciation expense for other property and equipment increased $338,000 principally due to depreciation of artificial lift equipment placed in service during fiscal 2015 and $273,000 of additional depreciation recognizing the impairment of GARP® equipment installations on three wells of a third party customer.
Other Economic Factors
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 production costs and capital expenditures. During fiscal 2014, we saw modest increases in certain oil field services and materials compared to the prior fiscal year. During fiscal 2015 to date, we have not seen material changes in costs. Product prices, operating costs and development costs may not always move in tandem.
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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. We have recently seen significant declines in crude oil prices and are uncertain if this downward price pressure will continue. If such lower crude oil prices persist, our revenues and cash flow going forward will be adversely impacted.
Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements to report during the quarter ending March 31, 2015.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Information about market risks for the three months ended March 31, 2015, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2014.
Commodity Price Risk
Our most significant market risk is the pricing for crude oil, natural gas and NGLs. All of such prices have declined significantly during the three months ended March 31, 2015. We expect energy prices to remain volatile and unpredictable. If energy prices decline further significantly, revenues and cash flow would significantly decline. In addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and dividends, and our ability to borrow and raise additional capital, as, if and when needed. Our general philosophy is not to hedge our commodity price risk. If we choose, we could 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 presently do not hold or issue derivative instruments for hedging or speculative purposes.
Interest Rate Risk
We currently have only a small exposure 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.
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2015 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.
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Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended March 31, 2015 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 15 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2014 Annual Report. Material developments in the status of those proceedings during the quarter ended March 31, 2015 are described in Part I. Item 1. "Financial Information" under Note 15 — Commitments and Contingencies in this Quarterly Report. We believe that the ultimate liability, if any, with respect to these 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, 2014 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, 2014.
ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
During the quarter ended March 31, 2015, the Company did not sell any equity securities that were not registered under the Securities Act.
Issuer Purchases of Equity Securities
During the quarter ended March 31, 2015, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and/or exercises of stock options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting.

Period |  | (a) Total Number of Shares (or Units) Purchased |  | (b) Average Price Paid per Share (or Units) |  | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |  | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Month of January 2015 |  | none |  | ___ |  | Not applicable |  | Not applicable
Month of February 2015 |  | none |  | ___ |  | Not applicable |  | Not applicable
Month of March 2015 |  | 756 shares of Common Stock |  | $6.48 |  | Not applicable |  | Not applicable

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
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 to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS |  | XBRL Instance Document
101.SCH |  | XBRL Taxonomy Extension Schema Document
101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document
101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EVOLUTION PETROLEUM CORPORATION
(Registrant)

|  | By: | /s/ RANDALL D. KEYS
|  |  | Randall D. Keys
|  |  | President and Chief Financial Officer
|  |  | Principal Financial Officer and
|  |  | Principal Accounting Officer
Date: May 8, 2015 |  |

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