10-Q 1 a10-qq3x17.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, 2017
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.)

1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o | Accelerated filer x
Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company o | Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2017, was 33,062,297.

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, 2017 and June 30, 2016 | 2
| Unaudited Consolidated Condensed Statements of Operations for the three and nine months ended March 31, 2017 and 2016 | 3
| Unaudited Consolidated Condensed Statements of Cash Flows for the nine months ended March 31, 2017 and 2016 | 4
| Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the nine months ended March 31, 2017 | 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 | 26
ITEM 4. | CONTROLS AND PROCEDURES | 26
PART II. OTHER INFORMATION | 27
ITEM 1. | LEGAL PROCEEDINGS | 27
ITEM 1A. | RISK FACTORS | 27
ITEM 2. | UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS | 27
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES | 27
ITEM 4. | MINE SAFETY DISCLOSURES | 27
ITEM 5. | OTHER INFORMATION | 27
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, 2017 |  | June 30, 2016
Assets |  |  |  |  |
Current assets |  |  |  |  |
Cash and cash equivalents | $ | 20,220,249 |  |  | $ | 34,077,060 |
Receivables | 3,372,199 |  |  | 2,638,188 |
Deferred tax asset | — |  |  | 105,321 |
Derivative assets, net | 47,965 |  |  | 14,132 |
Prepaid expenses and other current assets | 697,346 |  |  | 251,749 |
Total current assets | 24,337,759 |  |  | 37,086,450 |
Oil and natural gas property and equipment, net (full-cost method of accounting) | 62,771,528 |  |  | 59,970,463 |
Other property and equipment, net | 45,194 |  |  | 28,649 |
Total property and equipment | 62,816,722 |  |  | 59,999,112 |
Other assets | 312,842 |  |  | 365,489 |
Total assets | $ | 87,467,323 |  |  | $ | 97,451,051 |
Liabilities and Stockholders’ Equity |  |  |  |  |
Current liabilities |  |  |  |  |
Accounts payable | $ | 1,707,415 |  |  | $ | 5,809,107 |
Accrued liabilities and other | 694,051 |  |  | 2,097,951 |
State and federal income taxes payable | 457,306 |  |  | 621,850 |
Total current liabilities | 2,858,772 |  |  | 8,528,908 |
Long term liabilities |  |  |  |  |
Deferred income taxes | 14,814,714 |  |  | 11,840,693 |
Asset retirement obligations | 811,226 |  |  | 760,300 |
Total liabilities | 18,484,712 |  |  | 21,129,901 |
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; no shares outstanding at March 31, 2017 as all shares were redeemed November 14, 2016 (Note 8); and 317,319 shares outstanding at June 30, 2016 with a liquidation preference of $7,932,975 ($25.00 per share) | — |  |  | 317 |
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,062,297 shares and 32,907,863 as of March 31, 2017 and June 30, 2016, respectively | 33,062 |  |  | 32,907 |
Additional paid-in capital | 40,659,387 |  |  | 47,171,563 |
Retained earnings | 28,290,162 |  |  | 29,116,363 |
Total stockholders’ equity | 68,982,611 |  |  | 76,321,150 |
Total liabilities and stockholders’ equity | $ | 87,467,323 |  |  | $ | 97,451,051 |

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,
| 2017 |  | 2016 |  | 2017 |  | 2016
Revenues |  |  |  |  |  |  |  |  |  |  |
Crude oil | $ | 9,060,796 |  |  | $ | 5,005,955 |  |  | $ | 25,184,468 |  |  | $ | 18,897,572 |
Natural gas liquids | 464,641 |  |  | 597 |  |  | 464,730 |  |  | 2,332 |
Natural gas | — |  |  | 183 |  |  | (4 | ) |  | 1,204 |
Artificial lift technology services | — |  |  | 100,000 |  |  | — |  |  | 207,960 |
Total revenues | 9,525,437 |  |  | 5,106,735 |  |  | 25,649,194 |  |  | 19,109,068 |
Operating costs |  |  |  |  |  |  |
Production costs | 2,811,258 |  |  | 2,192,217 |  |  | 7,448,320 |  |  | 7,030,537 |
Cost of artificial lift technology services | — |  |  | 10,933 |  |  | — |  |  | 70,932 |
Depreciation, depletion and amortization | 1,523,475 |  |  | 1,268,800 |  |  | 4,104,424 |  |  | 3,958,644 |
Accretion of discount on asset retirement obligations | 13,562 |  |  | 11,695 |  |  | 39,892 |  |  | 34,555 |
General and administrative expenses * | 1,283,906 |  |  | 2,304,237 |  |  | 3,760,348 |  |  | 6,046,603 |
Restructuring charges ** | — |  |  | — |  |  | — |  |  | 1,257,433 |
Total operating costs | 5,632,201 |  |  | 5,787,882 |  |  | 15,352,984 |  |  | 18,398,704 |
Income (loss) from operations | 3,893,236 |  |  | (681,147 | ) |  | 10,296,210 |  |  | 710,364 |
Other |  |  |  |  |  |  |  |  |  |  |
Gain on realized derivative instruments, net | 3,350 |  |  | 1,795,431 |  |  | 3,440 |  |  | 3,960,059 |
Gain (loss) on unrealized derivative instruments, net | 47,965 |  |  | (1,314,044 | ) |  | 33,833 |  |  | 119,679 |
Delhi field insurance recovery related to pre-reversion event | — |  |  | — |  |  | — |  |  | 1,074,957 |
Interest and other income | 13,099 |  |  | 11,851 |  |  | 39,905 |  |  | 23,516 |
Interest expense | (20,317 | ) |  | (14,036 | ) |  | (61,373 | ) |  | (51,162 | )
Income (loss) before income taxes | 3,937,333 |  |  | (201,945 | ) |  | 10,312,015 |  |  | 5,837,413 |
Income tax provision (benefit) | 1,518,190 |  |  | (72,337 | ) |  | 3,768,463 |  |  | 2,051,521 |
Net income (loss) attributable to the Company | 2,419,143 |  |  | (129,608 | ) |  | 6,543,552 |  |  | 3,785,892 |
Dividends on preferred stock | — |  |  | 168,575 |  |  | 250,990 |  |  | 505,726 |
Deemed dividend on preferred shares called for redemption | — |  |  | — |  |  | 1,002,440 |  |  | — |
Net income (loss) available to common stockholders | $ | 2,419,143 |  |  | $ | (298,183 | ) |  | $ | 5,290,122 |  |  | $ | 3,280,166 |
Earnings (loss) per common share |  |  |  |  |  |  |
Basic | $ | 0.07 |  |  | $ | (0.01 | ) |  | $ | 0.16 |  |  | $ | 0.10 |
Diluted | $ | 0.07 |  |  | $ | (0.01 | ) |  | $ | 0.16 |  |  | $ | 0.10 |
Weighted average number of common shares |  |  |  |  |  |  |  |  |  |  |
Basic | 33,062,297 |  |  | 32,879,381 |  |  | 33,021,865 |  |  | 32,779,234 |
Diluted | 33,115,699 |  |  | 32,879,381 |  |  | 33,064,708 |  |  | 32,834,765 |

* General and administrative expenses for the three months ended March 31, 2017 and 2016 included non-cash stock-based compensation expense of $291,151 and $277,907, respectively. For the corresponding nine month periods, non-cash stock compensation expense was $878,023 and $708,746, respectively.
** Restructuring charges include $569,228 of non-cash impairment charges and $59,339 of non-cash stock compensation expense for the nine months ended March 31, 2016.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)

| Nine Months Ended March 31,
| 2017 |  | 2016
Cash flows from operating activities |  |  |  |  |
Net income attributable to the Company | $ | 6,543,552 |  |  | $ | 3,785,892 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Depreciation, depletion and amortization | 4,146,898 |  |  | 3,991,055 |
Impairments included in restructuring charge | — |  |  | 569,228 |
Stock-based compensation | 878,023 |  |  | 768,085 |
Accretion of discount on asset retirement obligations | 39,892 |  |  | 34,555 |
Settlements of asset retirement obligations | (157,910 | ) |  | — |
Deferred income taxes | 3,079,342 |  |  | (399,256 | )
(Gain) loss on derivative instruments, net | (37,273 | ) |  | (4,099,759 | )
Write-off of deferred loan costs | — |  |  | 50,414 |
Changes in operating assets and liabilities: |  |  |  |  |
Receivables | (723,161 | ) |  | 1,178,053 |
Prepaid expenses and other current assets | (445,597 | ) |  | 20,696 |
Accounts payable and accrued expenses | (1,808,566 | ) |  | (98,254 | )
Income taxes payable | (164,544 | ) |  | (35,405 | )
Net cash provided by operating activities | 11,350,656 |  |  | 5,765,304 |
Cash flows from investing activities |  |  |  |  |
Derivative settlement payments (paid) received | (318,618 | ) |  | 3,513,285 |
Capital expenditures for oil and natural gas properties | (10,096,475 | ) |  | (12,191,121 | )
Capital expenditures for other property and equipment | (32,260 | ) |  | (1,876 | )
Other assets | — |  |  | (161,345 | )
Net cash used in investing activities | (10,447,353 | ) |  | (8,841,057 | )
Cash flows from financing activities |  |  |  |  |
Proceeds from exercise of stock options | — |  |  | 51,000 |
Cash dividends to preferred stockholders | (250,990 | ) |  | (505,726 | )
Cash dividends to common stockholders | (6,116,323 | ) |  | (4,932,247 | )
Common share repurchases, including shares surrendered for tax withholding | (459,858 | ) |  | (1,355,880 | )
Tax benefits related to stock-based compensation | — |  |  | 3,727,913 |
Redemption of preferred shares | (7,932,975 | ) |  | — |
Other | 32 |  |  | (21,969 | )
Net cash used in financing activities | (14,760,114 | ) |  | (3,036,909 | )
Net decrease in cash and cash equivalents | (13,856,811 | ) |  | (6,112,662 | )
Cash and cash equivalents, beginning of period | 34,077,060 |  |  | 20,118,757 |
Cash and cash equivalents, end of period | $ | 20,220,249 |  |  | $ | 14,006,095 |

Supplemental disclosures of cash flow information: | Nine Months Ended March 31,
| 2017 |  | 2016
Income taxes paid | $ | 1,383,773 |  |  | $ | 480,000 |
Louisiana carryback income tax refund and related interest received | — |  |  | 1,556,999 |
Non-cash transactions: |  |  |  |  |
Change in accounts payable used to acquire property and equipment | (3,181,640 | ) |  | (130,202 | )
Deferred loan costs charged to oil and gas property costs | — |  |  | 107,196 |
Oil and natural gas property costs incurred through recognition of asset retirement obligations | 14,119 |  |  | — |
Settlement of accrued treasury stock purchases | — |  |  | (170,283 | )
Royalty rights acquired through non-monetary exchange of patent and trademark assets | — |  |  | 108,512 |

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, 2017
(Unaudited)

| Preferred |  | Common Stock |  |  |  |  |  |  |  |
| Additional Paid-in Capital |  | Retained Earnings |  | Treasury Stock |  | Total Stockholders' Equity
| Shares |  | Par Value |  | Shares |  | Par Value |
Balance at June 30, 2016 | 317,319 |  |  | $ | 317 |  |  | 32,907,863 |  |  | $ | 32,907 |  |  | $ | 47,171,563 |  |  | $ | 29,116,363 |  |  | $ | — |  |  | $ | 76,321,150 |
Issuance of restricted common stock | — |  |  | — |  |  | 227,889 |  |  | 228 |  |  | (196 | ) |  | — |  |  | — |  |  | 32 |
Common share repurchases, including shares surrendered for tax withholding | — |  |  | — |  |  | (73,455 | ) |  | — |  |  | — |  |  | — |  |  | (459,858 | ) |  | (459,858 | )
Retirements of treasury stock | — |  |  | — |  |  | — |  |  | (73 | ) |  | (459,785 | ) |  | — |  |  | 459,858 |  |  | — |
Stock-based compensation | — |  |  | — |  |  | — |  |  | — |  |  | 878,023 |  |  | — |  |  | — |  |  | 878,023 |
Redemption of preferred shares | (317,319 | ) |  | (317 | ) |  | — |  |  | — |  |  | (6,930,218 | ) |  | (1,002,440 | ) |  | — |  |  | (7,932,975 | )
Net income attributable to the Company | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 6,543,552 |  |  | — |  |  | 6,543,552 |
Common stock cash dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (6,116,323 | ) |  | — |  |  | (6,116,323 | )
Preferred stock cash dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (250,990 | ) |  | — |  |  | (250,990 | )
Balance at March 31, 2017 | — |  |  | $ | — |  |  | 33,062,297 |  |  | $ | 33,062 |  |  | $ | 40,659,387 |  |  | $ | 28,290,162 |  |  | $ | — |  |  | $ | 68,982,611 |

See accompanying notes to consolidated condensed financial statements.
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Evolution Petroleum Corporation And 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 and production of oil and gas reserves.
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 2016 Annual Report on Form 10-K for the fiscal year ended June 30, 2016, 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. As a result of the separation of our artificial lift technology operations at December 31, 2015, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells which used our artificial lift technology, together with service revenues derived from the use of the Company’s technology on third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services.
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 (a) 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, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets and (f) 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.
New Accounting Pronouncements.
In August 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") by one year and allows entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method. The Company expects that additional disclosures will be required as a result of adopting ASU 2014-09 and is currently assessing the impact of the guidance on its consolidated financial statements.
On February 25, 2016, the FASB issued ASU 2016-02 , Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than twelve months. In addition, this standard requires both lessees and
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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
New Accounting Pronouncements Adopted.
The Company early adopted ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, to be applied prospectively effective for the three months ended September 30, 2016, the first quarter of our fiscal year. This amended guidance simplifies the balance sheet position presentation and reduces complexity in accounting for deferred income tax assets and liabilities. The update requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. As a result, current deferred tax assets of $105,321 have been netted together with noncurrent deferred income tax liabilities on the March 31, 2017 consolidated condensed balance sheet. The prior period presented has not been retrospectively adjusted.
The Company early adopted ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting, effective for the three months ended September 30, 2016. This amended guidance simplifies and improves several aspects of the accounting for employee share-based payment transactions. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. For vestings which occurred in the nine months ended March 31, 2017, a related tax deficiency of $24,597 was recognized in income tax expense. The Company also elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flows. Accordingly, such statements for pre-adoption periods will continue to present excess tax benefits in the financing section. The amended guidance permits entities to make an accounting policy election related to how forfeitures will impact the recognition of compensation cost for stock-based compensation: to continue to estimate the total number of awards for which the requisite service period will not be rendered as currently required or, to be applied on a modified retrospective basis, to account for forfeitures as they occur. Upon early adoption, the Company elected to change its accounting policy to account for forfeitures as they occur. Except for income tax expense mentioned above, none of the other provisions in this amended guidance had a material impact on our condensed consolidated financial statements.
Note 2 — Receivables
As of March 31, 2017 and June 30, 2016, our receivables consisted of the following:

| March 31, 2017 |  | June 30, 2016
Receivables from oil and gas sales | $ | 3,353,528 |  |  | $ | 2,637,593 |
Receivable from settled derivatives | 10,850 |  |  | — |
Other | 7,821 |  |  | 595 |
Total receivables | $ | 3,372,199 |  |  | $ | 2,638,188 |

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Notes to Unaudited Consolidated Condensed Financial Statements
Note 3 — Prepaid Expenses and Other Current Assets
As of March 31, 2017 and June 30, 2016, our prepaid expenses and other current assets consisted of the following:

| March 31, 2017 |  | June 30, 2016
Prepaid insurance | $ | 71,911 |  |  | $ | 168,681 |
Retainers and deposits | 7,553 |  |  | 30,568 |
Prepaid federal and state income taxes | 531,713 |  |  | — |
Other prepaid expenses | 86,169 |  |  | 52,500 |
Prepaid expenses and other current assets | $ | 697,346 |  |  | $ | 251,749 |

Note 4 — Property and Equipment
As of March 31, 2017 and June 30, 2016, our oil and natural gas properties and other property and equipment consisted of the following:

| March 31, 2017 |  | June 30, 2016
Oil and natural gas properties |  |  |  |  |
Property costs subject to amortization | $ | 84,337,308 |  |  | $ | 77,408,353 |
Less: Accumulated depreciation, depletion, and amortization | (21,565,780 | ) |  | (17,437,890 | )
Unproved properties not subject to amortization | — |  |  | — |
Oil and natural gas properties, net | $ | 62,771,528 |  |  | $ | 59,970,463 |
Other property and equipment |  |  |  |  |
Furniture, fixtures, office equipment and other, at cost | $ | 231,432 |  |  | $ | 235,752 |
Less: Accumulated depreciation | (186,238 | ) |  | (207,103 | )
Other property and equipment, net | $ | 45,194 |  |  | $ | 28,649 |

During the nine months ended March 31, 2017, the Company incurred capital expenditures of $6.9 million for the Delhi field, including approximately $4.8 million for the NGL plant project. We have incurred approximately $26.3 million on a cumulative basis for the NGL plant.
Note 5 — Other Assets
As of March 31, 2017 and June 30, 2016, other assets consisted of the following:

| March 31, 2017 |  | June 30, 2016
Royalty rights | $ | 108,512 |  |  | $ | 108,512 |
Less: Accumulated amortization of royalty rights | (16,955 | ) |  | (6,782 | )
Investment in Well Lift Inc., at cost | 108,750 |  |  | 108,750 |
Deferred loan costs | 168,972 |  |  | 168,972 |
Less: Accumulated amortization of deferred loan costs | (56,437 | ) |  | (13,963 | )
Other assets, net | $ | 312,842 |  |  | $ | 365,489 |

The Company accounts for its investment in Well Lift Inc. using the cost method under which any return of capital reduces cost and any dividends paid are recorded as income. Investment value is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.
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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 6 — Accrued Liabilities and Other
As of March 31, 2017 and June 30, 2016, our other current liabilities consisted of the following:

| March 31, 2017 |  | June 30, 2016
Accrued incentive and other compensation | $ | 389,746 |  |  | $ | 999,172 |
Asset retirement obligations due within one year | — |  |  | 201,896 |
Accrued royalties, including suspended accounts | 41,640 |  |  | 49,580 |
Accrued franchise taxes | 114,651 |  |  | 62,834 |
Accrued restructuring costs | 103,174 |  |  | 419,488 |
Payables for settled derivatives | — |  |  | 318,708 |
Other accrued liabilities | 44,840 |  |  | 46,273 |
Accrued liabilities and other | $ | 694,051 |  |  | $ | 2,097,951 |

Accrued Restructuring Costs
On December 31, 2015 we terminated three employees of the Company in connection with the separation of our artificial lift technology operations and recorded a $1,257,433 restructuring charge which consisted of $569,228 for the impairment of technology assets, $59,339 of stock-based compensation from accelerated vesting of terminated employees' equity awards and $628,866 of accrued salary and benefit continuation expenses. The separation agreements included releases from liabilities and other provisions including agreements not to compete.
Our current estimate of remaining restructuring obligations as of March 31, 2017 is as follows:

| December 31, 2015 |  | Payments (1) |  | March 31, 2017
Salary expense | $ | 530,387 |  |  | $ | (441,989 | ) |  | $ | 88,398 |
Payroll taxes and benefits expense | 98,479 |  |  | (83,703 | ) |  | 14,776 |
Accrued liability for restructuring costs | $ | 628,866 |  |  | $ | (525,692 | ) |  | $ | 103,174 |

(1) During the nine months ended March 31, 2017, we paid $265,193 of salary continuation and $51,121 of related payroll taxes and benefits.
Note 7 — 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, 2017 and for the year ended June 30, 2016:

| March 31, 2017 |  | June 30, 2016
Asset retirement obligations — beginning of period | $ | 962,196 |  |  | $ | 772,990 |
Liabilities incurred | 14,119 |  |  | 28,505 |
Liabilities settled | (157,164 | ) |  | — |
Liabilities sold (a) | (47,817 | ) |  | — |
Accretion of discount | 39,892 |  |  | 49,054 |
Revision of previous estimates | — |  |  | 111,647 |
Asset retirement obligations — end of period | $ | 811,226 |  |  | $ | 962,196 |
Less current portion in accrued liabilities (b) | — |  |  | (201,896 | )
Long-term portion of asset retirement obligations | $ | 811,226 |  |  | $ | 760,300 |

(a) We conveyed our interest in a well to the previous operator in exchange for the assumption of our asset retirement obligation.
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Notes to Unaudited Consolidated Condensed Financial Statements
(b) As we have now retired our remaining operated wells, our asset retirement obligations consist entirely of our working interest obligations in the Delhi field.
Note 8 — Stockholders’ Equity
Common Stock
As of March 31, 2017, we had 33,062,297 sh ares of common stock outstanding.
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. This rate was subsequently adjusted to $0.05 per share during the quarter ended March 31, 2015. During the nine months ended March 31, 2017, the Board of Directors made two increases to the quarterly cash dividend resulting in rates of $0.065 per share for the December 31, 2016 dividend payment and $0.07 per share for the March 31, 2017 dividend payment.
During the nine months ended March 31, 2017, the Company declared three quarterly dividends on its common stock and paid $6,116,323 to its common stockholders.
On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since commencing in June 2015, 265,762 shares have been repurchased at an average price of $6.05 per share (totaling $1,609,008). There have been no shares repurchased in the open market since mid-December 2015. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.
During the nine months ended March 31, 2017, the Company acquired 73,455 shares of treasury stock at an average cost of $6.26 per share (totaling $459,858) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the quarter. The treasury shares were subsequently canceled.
During the nine months ended March 31, 2016, the Company purchased 202,390 shares of treasury stock at an average cost of $5.80 per share (totaling $1,173,899) under its share repurchase program and also acquired 2,230 shares of treasury stock at an average cost of $5.25 per share (totaling $11,698) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the quarter. All treasury shares were subsequently canceled.
Series A Cumulative Perpetual Preferred Stock Called for Redemption
On September 30, 2016, the Company declared the preferred dividend for the month of October 2016 and elected to redeem all 317,319 outstanding shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock. The redemption occurred on November 14, 2016 at the issue's $25.00 per share liquidation value plus all accumulated and unpaid distributions from October 31, 2016 (the last dividend payment date before the redemption date) through the redemption date, for an aggregate redemption price of approximately $25.082639 per share:

Consideration paid to preferred shareholders at redemption at liquidation preference | $ | 7,932,975 |
Payments for dividends accrued at September 30, 2016 (1) | $ | 82,415 |

(1) Includes the monthly dividend for October 2016 declared by the Company.
On September 30, 2016, in connection with the planned redemption, the Company recorded a deemed dividend of $1,002,440, representing the difference between the redemption consideration paid and the historical net issuance proceeds of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share.
The Series A Cumulative Preferred Stock was not convertible into our common stock and there were no sinking fund or redemption rights available to the holders thereof. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranked senior to our common stockholders, but subordinate to any of our existing and future debt. Dividends on the Series A Cumulative Preferred Stock accrued and accumulated 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
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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Board of Directors through its Dividend Committee. We paid cash dividends of $250,990 and $505,726 to holders of our Series A Preferred Stock during the nine months ended March 31, 2017 and 2016, respectively.
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2016, all preferred and common dividends were treated for tax purposes as qualified dividend income to recipients. Based on our current projections for the fiscal year ending June 30, 2017, we also expect all common and remaining preferred dividends for such period will be treated as qualified dividend income.
Note 9 — Stock-Based Incentive Plan
At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of March 31, 2017, 1,100,000 shares were available for grant under the 2016 Plan.
At March 31, 2017, there were no shares remaining available for grant under the 2004 Plan. We were authorized to issue 6,500,000 shares of common stock under the 2004 Plan prior to its scheduled expiration on October 24, 2017. In connection with the adoption of the 2016 Plan, the Board terminated the 2004 Plan on December 8, 2016 and 32,146 remaining reserved shares were released to the Company's authorized but unissued and unreserved shares. All outstanding awards granted under the 2004 Plan continue to be subject to the terms and conditions as set forth in the agreements evidencing such awards and the terms of the 2004 Plan. Under these agreements, we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company.
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, 2017, and the changes during the period:

| Number of Stock Options |  | Weighted Average Exercise Price |  | Aggregate Intrinsic Value (1) |  | Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at July 1, 2016 | 35,231 |  |  | $ | 2.19 |  |  |  |  |  |
Stock Options outstanding at March 31, 2017 | 35,231 |  |  | $ | 2.19 |  |  | $ | 204,692 |  |  | 0.4
Vested and exercisable at March 31, 2017 | 35,231 |  |  | $ | 2.19 |  |  | $ | 204,692 |  |  | 0.4

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($8.00 as of March 31, 2017) 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.
In August 2014, December 2015 and September 2016, 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 are reserved from the Plan, but will be issued only upon the attainment of specified performance-based or market-based vesting provisions.
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Notes to Unaudited Consolidated Condensed Financial Statements
Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value 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 four-year term. As of March 31, 2017, certain contingent performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense will be recorded at that time and amortization would continue over the remaining expected vesting period.
Market-based awards granted in 2014 and 2015 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. Market-based awards granted in 2016 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 an index consisting of designated peer companies during defined measurement periods. The fair value and expected vesting 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. During the nine months ended March 31, 2017, we granted market-based awards with grant date fair values ranging from $3.42 to $5.62 per share, all with an expected vesting period of 2.83 years, based on the various quartiles of comparative market performance. During the fiscal year ended June 30, 2016, we granted market-based awards with grant date fair values ranging from $2.93 to $5.07 per share, all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance. During the fiscal year ended June 30, 2015, we granted market-based awards with grant date fair values ranging from $4.26 to $8.40 per share and with expected vesting periods of 3.30 years 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.
Unvested Restricted Stock awards at March 31, 2017 consisted of the following:

| Number of Restricted Shares |  | Weighted Average Grant-Date Fair Value
Service-based awards | 219,940 |  |  | $ | 7.08 |
Performance-based awards | 54,475 |  |  | 5.67 |
Market-based awards | 119,227 |  |  | 4.97 |
Unvested Restricted Stock at March 31, 2017 | 393,642 |  |  | $ | 6.25 |

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2017:

| Number of Restricted Shares |  | Weighted Average Grant-Date Fair Value |  | Unamortized Compensation Expense at March 31, 2017 |  | Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016 | 406,848 |  |  | $ | 6.74 |  |  |  |  |
Service-based shares granted | 86,563 |  |  | 7.02 |  |  |  |  |
Performance-based shares granted | 54,475 |  |  | 5.67 |  |  |  |  |
Market-based shares granted | 54,475 |  |  | 5.44 |  |  |  |  |
Vested | (208,719 | ) |  | 7.17 |  |  |  |  |
Unvested Restricted Stock at March 31, 2017 | 393,642 |  |  | $ | 6.25 |  |  | $ | 1,923,545 |  |  | 2.2

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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Unvested Contingent Restricted Stock awards at March 31, 2017 consisted of the following:

| Number of Contingent Restricted Shares |  | Weighted Average Grant-Date Fair Value
Performance-based awards | 39,403 |  |  | $ | 7.02 |
Market-based awards | 73,867 |  |  | 3.37 |
Unvested contingent shares at March 31, 2017 | 113,270 |  |  | $ | 4.64 |

The following table sets forth Contingent Restricted Stock transactions for the nine months ended March 31, 2017:

| Number of Contingent Restricted Shares |  | Weighted Average Grant-Date Fair Value |  | Unamortized Compensation Expense at March 31, 2017 (1) |  | Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016 | 91,172 |  |  | $ | 5.21 |  |  |  |  |
Performance-based awards granted | 27,237 |  |  | 5.67 |  |  |  |  |
Market-based awards granted | 27,237 |  |  | 3.42 |  |  |  |  |
Vested | (32,376 | ) |  | 6.09 |  |  |  |  |
Unvested contingent shares at March 31, 2017 | 113,270 |  |  | $ | 4.64 |  |  | $ | 149,015 |  |  | 2.2

(1) Excludes $276,702 of potential future compensation expense for contingent 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, 2017 and 2016 was $291,151 and $277,907, respectively. For the corresponding nine month periods, non-cash stock compensation expense was $878,023 and $768,085, respectively.
Note 10 — Derivatives
In early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecasted production. The Company's objectives for this program are to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The Company may use both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.
The Company does not intend to enter into derivative instruments for speculative or trading purposes.
The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedgin g ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in income. Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings.
These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.
As of March 31, 2017 the Company held a net asset position with its counterparty which had a fair value of $47,965 and has not subsequently acquired any crude oil derivative positions.
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Notes to Unaudited Consolidated Condensed Financial Statements
For the nine months ended March 31, 2017, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $37,273 consisting of a realized gain of $3,440 on settled derivatives and an unrealized net gain of $33,833 on unsettled derivatives. For the nine months ended March 31, 2016, the Company recorded in its consolidated statement of operations a gain on derivative instruments of $4,079,738 consisting of an unrealized gain of $119,679 on open positions and a realized net gain of $3,960,059 on settled positions.
The following sets forth a summary of the Company's crude oil derivative positions at average NYMEX WTI prices as of March 31, 2017:

Period |  | Type of Contract |  | Volumes (in Bbls./day) |  | Weighted Average Floor Price per Bbl. |  | Weighted Average Ceiling Price per Bbl.
Months of April 2017 through May 2017 |  | Costless Collar |  | 819.7 |  | $50.00 |  | $58.00

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:
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 Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of March 31, 2017. All items included in the tables below are Level 2 inputs within the fair value hierarchy:

|  | March 31, 2017
Asset (Liability) |  | Gross Amounts Recognized |  | Gross Amounts Offset in the Consolidated Balance Sheet |  | Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets |  | $ | 49,366 |  |  | $ | (1,401 | ) |  | $ | 47,965 |
Current derivative liabilities |  | (1,401 | ) |  | 1,401 |  |  | — |
Total |  | $ | 47,965 |  |  | $ | — |  |  | $ | 47,965 |

The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparty's credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.
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.
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Notes to Unaudited Consolidated Condensed Financial Statements
There were neither unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the nine months ended March 31, 2017. 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 various 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 ended June 30, 2013 through June 30, 2016 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2016 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.
We recognized income tax expense of $3,768,463 and $2,051,521 for the nine months ended March 31, 2017 and 2016, respectively, with corresponding effective tax rates of 37% and 35%. Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation and other permanent differences. The effective tax rate for the nine months ended March 31, 2017 was slightly higher than the statutory federal rate as a result of state income taxes and the tax effects of stock-based compensation, offset by percentage depletion in excess of basis.
Note 13 — Net Income Per Share
The following table sets forth the computation of basic and diluted income per share:

| Three Months Ended March 31, |  | Nine Months Ended March 31,
| 2017 |  | 2016 |  | 2017 |  | 2016
Numerator |  |  |  |  |  |  |  |  |  |  |
Net income (loss) available to common shareholders | $ | 2,419,143 |  |  | $ | (298,183 | ) |  | $ | 5,290,122 |  |  | $ | 3,280,166 |
Denominator |  |  |  |  |  |  |  |  |  |  |
Weighted average number of common shares — Basic | 33,062,297 |  |  | 32,879,381 |  |  | 33,021,865 |  |  | 32,779,234 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |  |  |
Contingent restricted stock grants | 27,216 |  |  | — |  |  | 17,860 |  |  | 8,418 |
Stock options | 26,186 |  |  | — |  |  | 24,983 |  |  | 47,113 |
Weighted average number of common shares and dilutive potential common shares used in diluted EPS | 33,115,699 |  |  | 32,879,381 |  |  | 33,064,708 |  |  | 32,834,765 |
Net income (loss) per common share — Basic | $ | 0.07 |  |  | $ | (0.01 | ) |  | $ | 0.16 |  |  | $ | 0.10 |
Net income (loss) per common share — Diluted | $ | 0.07 |  |  | $ | (0.01 | ) |  | $ | 0.16 |  |  | $ | 0.10 |

Outstanding potentially dilutive securities as of March 31, 2017 were as follows:

Outstanding Potentially Dilutive Securities |  | Weighted Average Exercise Price |  | At March 31, 2017
Contingent Restricted Stock grants |  | $ | — |  |  | 113,270 |
Stock Options |  | 2.19 |  |  | 35,231 |
Total outstanding potentially dilutive securities |  | $ | 0.52 |  |  | 148,501 |

Outstanding potentially dilutive securities as of March 31, 2016 were as follows:

Outstanding Potentially Dilutive Securities |  | Weighted Average Exercise Price |  | At March 31, 2016
Contingent Restricted Stock grants |  | $ | — |  |  | 91,172 |
Stock Options |  | 2.36 |  |  | 65,231 |
Total outstanding potentially dilutive securities |  | $ | 0.98 |  |  | 156,403 |

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Notes to Unaudited Consolidated Condensed Financial Statements
Note 14 — Senior Secured Credit Agreement
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replaces the Company's previous unsecured credit facility which expired in April 2016. The initial borrowing base under the Facility was set at $10,000,000. As of March 31, 2017, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.
Borrowings from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.
The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.00%. The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Facility.
In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $112,535 as of March 31, 2017.
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.
On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks 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. The plaintiffs subsequently filed an amended petition joining the Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. The district court dismissed the claim of Brooks against NGS Sub Corp. and the Company because Brooks purchased the land where the well is located subsequent to the divestiture of the property by NGS Sub. Corp. The claim of Hawkins is still being defended. Trial is currently scheduled for late November 2017. We will continue to vigorously defend the claims and based on the input of our legal counsel, we consider the likelihood of a material loss to the Company in this matter to be remote.
Lease Commitments. We have a non-cancelable operating lease for office space that expires on May 31, 2019. Future minimum lease commitments as of March 31, 2017 under this operating lease are as follows:

Twelve months ended March 31, |
2018 | $ | 73,073 |
2019 | $ | 73,073 |
2020 | $ | 12,179 |

Rent expense for the three months ended March 31, 2017 and 2016 was $14,656 and $46,286, respectively. Rent expense for the corresponding nine month periods was $68,081 and $137,185, respectively.
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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, 2016 (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 2016 Annual Report on Form 10-K for the year ended June 30, 2016 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 and production of oil and gas reserves within known oil and gas resources utilizing conventional technology with a focus on creating value 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 maximize the value realized by our stockholders from our assets, particularly our core Delhi asset.
We are currently funding our fiscal 2017 capital program from working capital and net cash flows from our properties.
Highlights for our Third Quarter of Fiscal 2017 and Operations Update
"Current quarter" refers to the three months ended March 31, 2017, the Company's third quarter of fiscal 2017.
"Prior quarter" refers to the three months ended December 31, 2016, the Company's second quarter of fiscal 2017.
"Year-ago quarter" refers to the three months ended March 31, 2016, the Company's third quarter of fiscal 2016.
Highlights

• | Revenues for the fiscal third quarter of 2017 were $9.5 million, an increase of 87% over the third quarter of 2016.

• | Net income was $2.4 million in the third quarter of 2017, or $0.07 per diluted common share, versus a net loss of $0.3 million, or $0.01 per common diluted share, in the year ago quarter.

• | The Company paid its fourteenth consecutive quarterly cash dividend on common shares, in the amount of $0.07 per share, which reflected an 8% increase over the prior quarter.

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• | Delhi natural gas liquid ("NGL") sales commenced in the current quarter. Gross NGL sales volumes averaged 830 barrels per day as volumes ramped up during the quarter. For the current quarter, our net NGL sales volumes were 218 barrels per day and the net realized NGL price was $23.71 per barrel.

• | Gross oil production in the Delhi field was 2.7% higher in the current quarter, increasing to 7,786 barrels of oil per day (“BOPD”) from 7,580 BOPD, continuing a positive trend in optimizing production in the flood. For the current quarter, net oil production increased to 2,042 BOPD, from 1,987 BOPD in the prior quarter and the net realized oil price per barrel was $49.29 compared to $46.66 per barrel in the prior quarter.

• | Our net total production increased to 2,260 barrels of oil equivalent per day ("BOEPD"), from 1,987 BOPD in the prior quarter, primarily attributable to the Delhi NGL volumes of 218 BOEPD.

• | Lifting costs per unit at Delhi were $13.82 per barrel, which represents a 10.2% increase over the prior quarter and a 5.3% increase over the year-ago quarter. The increase in lifting costs is almost entirely attributable to incremental costs for the NGL plant, which commenced operations at the beginning of the quarter.

• | The Company ended the quarter with $21.5 million of working capital, substantially all of which was cash. With essentially all of our capital spending for the NGL plant completed in the prior quarter, our working capital increased by $2.9 million from the prior quarter, despite paying $2.3 million in common stock dividends during the quarter.

• | The Company remains debt free.

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, 2016.
Delhi Field - Enhanced Oil Recovery Project
Gross oil production at Delhi in the third quarter of fiscal 2017 averaged 7,786 BOEPD, a 2.7% increase from the prior quarter and an increase of 12.5% from the year-ago quarter. There continues to be increased production from conformance projects and other production enhancement operations. Gross NGL sales for this initial quarter of production were 830 BOEPD. After an initial startup period in January 2017, the NGL plant averaged approximately 1,100 BOEPD on a gross basis during February and March 2017. During these two months, the plant operated at 20% to 30% below its full capacity. Based on results seen in this initial operating period, we believe the plant should be able to achieve over 1,400 BOEPD at full capacity. Startup of new processing plants often involves a period of adjustments to reach equilibrium operations and we are working with the operator to resolve the issues which are currently limiting full production capacity for the plant. Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate royalty interests of 7.2%. This yields a total net revenue interest of 26.2%.
Field operating expenses were $13.82 per barrel in the current quarter compared to $12.54 in the prior quarter. Our net share of third quarter lease operating expenses in the Delhi field were $2.8 million in the current quarter, which was $0.5 million higher than the prior quarter, and $0.6 million over the year ago quarter. We estimate that incremental costs associated with the NGL plant were approximately $0.5 million, which includes certain non-recurring costs associated with the start-up and early operation of the plant. Without these additional NGL plant costs, we estimate that total field lifting costs were comparable between the quarters. CO 2 costs for the current and prior quarters were essentially flat as a higher current quarter unit purchase cost, which is tied directly to higher realized oil prices in the field, was offset by a modest decrease in volumes, reflecting an injection rate decline from 67.0 MMcf per day in the prior quarter to 66.3 MMcf per day in the current quarter. Calculated on total net production volumes, our total CO 2 costs were $5.16 per equivalent barrel in the current quarter compared to $5.70 in the prior quarter. Under our contract with the operator, purchased CO 2 is priced at 1% of the realized oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of 8% plus transportation costs of $0.20 per Mcf.
Following a December 31, 2016 startup of the NGL recovery plant, NGL sales commenced in the current quarter, resulting in $0.5 million of NGL revenues. Our net NGL production was 218 BOEPD and was sold at an average price of $23.71 per barrel. Production from the NGL plant is transported by truck to a fractionation plant in East Texas. Under our current marketing contract, we receive market index pricing for each NGL component, based on the processed yield, less transportation and fractionation (processing) fees. There may also be a quality deduction for NGL's that do not meet the purchaser's specifications. The current mix of products contains a large percentage (over 65%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for NGL's during this winter period was seasonally
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high, but our price was adversely affected by quality deductions on a large percentage of the NGL's produced during the quarter. We are working with the operator to better attain the purchaser's specification. The operator has initially charged certain costs associated with the NGL plant as post-production processing charges against our royalty interests. We are reviewing the basis for this cost allocation.
The NGL plant includes an electric turbine to convert methane and part of the ethane removed by the plant to electricity. This electricity will provide power to the NGL plant and is expected to supply excess power to the CO 2 recycle facility, which is expected to reduce part of existing power costs in the Delhi field. During the first quarter of production, with the NGL plant operating at less than full capacity and ramping up the flow rate during the quarter, the Company has yet to see measurable savings in power costs. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane), thereby increasing the purity of the CO 2 recycle stream and improving the efficiency of the flood. Over time, it is expected to increase the recovery of crude oil in the field. The plant is also providing feedstock to power the electric turbine and producing significant quantities of higher value NGL's for sale.
During the period since reversion, we have participated in multiple conformance and re-entry projects, as well as workovers to convert idle wells into producers, that were primarily responsible for the increased production rates. We are continuing to evaluate similar projects within the field in order to optimize production and increase ultimate reserve recoveries.
Liquidity and Capital Resources
We had $20.2 million and $34.1 million in cash and cash equivalents at March 31, 2017 and June 30, 2016, respectively. In addition, we had $10 million of availability under our senior secured reserve-based credit facility on both dates.
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") with MidFirst Bank. The Facility provides a senior secured revolving credit facility with a borrowing base of $10 million (the “Borrowing Base”) and a maximum borrowing amount of $50 million. The Facility matures on April 11, 2019, and is secured by substantially all of the Company’s assets.
The Borrowing Base is subject to periodic redeterminations and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on May 15 and November 15 of each year. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and changes to certain hedging positions. With volatility in commodity prices, our borrowing base and related commitments under the Facility could be reduced in the future. The Facility bears interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. In November 2016, as part of our semiannual borrowing base redetermination, the lender's commitment, based on our request, was reaffirmed at $10 million, with our next borrowing base redetermination scheduled for May 2017.
During the nine months ended March 31, 2017, we funded our operations with cash generated from operations and cash on hand. At March 31, 2017, our working capital was $21.5 million, compared to working capital of $28.6 million at June 30, 2016. The $7.1 million decrease in working capital is primarily attributable to a $13.9 million decrease in cash impacted by the $7.9 million payment for the redemption of all of our preferred stock outstanding, a $4.1 million decrease in payables and a $1.4 million decrease in accrued liabilities.
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. In June 2015, the Company began using derivative instruments to reduce its exposure to short term oil price volatility with the goal of achieving a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. The Company has used both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. During the current quarter we acquired costless collars to mitigate price risk on approximately one-third of our oil production for the months of March, April and May 2017. We have no derivative commitments beyond May 31, 2017 at this time. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth are significantly impacted by the prices we receive for our production.
Payment of free cash flow in excess of our operating and capital requirements through cash dividends and potential repurchases of 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. In the prior quarter with the NGL plant capital expenditures substantially completed, the Company had previously announced an increase in the common stock cash dividend to $0.065 per share, effective with the dividend payment in December 2016. Following the redemption of our preferred stock and the end of its dividend requirement,
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the Company announced a further increase in the common stock dividend to $0.07 per share, effective with the dividend payment in March 2017. The Board of Directors reviews the quarterly dividend rate in light of current financial results and operations, forecasted financial results, the timing of further expansion of Delhi development and the outlook for crude oil prices.
In May 2015, we established a stock repurchase plan to allow us to acquire up to $5.0 million of our common stock over time, of which we have approximately $3.4 million remaining. The actual timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. In general, our share repurchase program is limited to discretionary funds and is of lesser importance than our primary objectives related to our development capital spending at Delhi and our common stock dividend program. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time.
Our preference is to remain debt free under our current operating plans, but we have access to a senior secured credit facility for oil and gas development if needed. In addition, we have a maximum of $500 million authorized under an effective shelf registration statement on file with the Securities and Exchange Commission under which we may sell securities from time to time in one or more offerings. We may choose to evaluate new growth opportunities through acquisitions or other transactions. In that event, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.
Capital Budget - Delhi Field
During the nine months ended March 31, 2017, we incurred $6.9 million of capital expenditures, which included $4.8 million for the NGL plant and $2.1 million in capital workovers for conformance projects and production enhancement operations and capital for drilling a new water injection well.
As of March 31, 2017, we believe we have incurred and recorded substantially all of the costs for the NGL plant, totaling approximately $26.3 million. Our current expectations for capital spending during the remainder of our fiscal year ended June 30, 2017 include a few additional conformance and workover operations totaling less than $1 million net to Evolution. Based on meetings with the field operator, we have identified new opportunities to invest in the Delhi field during the second half of this calendar year, which is part of our fiscal year 2018. The majority of this capital is planned for an infill drilling program to enhance production in the current developed area of the flood. This program will consist of up to five new CO 2 injection wells and seven new production wells and will target productive oil zones which we believe are not being swept effectively by the current CO 2 flood. This infill program is expected to both add production and increase ultimate recoveries above the current proved oil reserves. There are other capital projects proposed to add infrastructure for the Phase Five expansion of the Delhi field so that it can be developed in a safe and responsible manner. We currently expect this expansion to occur during calendar 2018. Funding for our anticipated capital expenditures at Delhi over the next fiscal year is expected to be met from cash flows from operations and current working capital.
Overview of Cash Flow Activities
Net cash provided by operating activities from operations was $11.4 million and $5.8 million for the nine months ended March 31, 2017 and 2016, respectively. The $5.6 million increase in cash provided by operations between these two nine month periods was due to $2.8 million of higher net income and a $7.0 million increase in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations, partially offset by $4.2 million of cash used by operating assets and liabilities. The change in non-cash expenses and adjustments was primarily due to deferred income taxes, which increased in the current nine-month period and declined slightly in the prior period, and a significant decrease in derivatives activities between the periods. The change in operating assets and liabilities was primarily attributable to an increase in receivables which reflected improved revenue in the current period and a reduction in accounts payable based on faster payment of operating and capital costs to the Delhi field operator as part of the June 2016 litigation settlement.
Net cash used in investing activities was $10.4 million and $8.8 million for the nine months ended March 31, 2017 and 2016, respectively. The $1.6 million increase in cash outflow was primarily due to a $3.8 million decline in cash provided by derivative settlements partially offset by $2.1 million of lower current year oil and gas capital expenditures.
Net cash used by financing activities for the nine months ended March 31, 2017 and 2016 was $14.8 million and $3.0 million, respectively. The $11.7 million increase was principally due to the $7.9 million redemption of preferred shares during November 2016, together with a $3.7 million decrease in tax benefits related to stock-based compensation.
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New Accounting Pronouncements Adopted
As discussed in Note 1 "Organization and Basis of Preparation," the Company early adopted two new accounting pronouncements, effective for the three months ended September 30, 2016, the first quarter of fiscal year 2017.
ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. The Company elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flows. Accordingly, such statements for pre-adoption periods will continue to present excess tax benefits in the financing section. For vestings that occurred in the nine months ended March 31, 2017, a related tax deficiency of $24,597 was included in the operating section of the statements of cash flows as income tax expense and for the nine months ended March 31, 2016, $3.7 million of cash provided by tax benefits related to stock-based compensation was included in the financing section of such statements. Except for the accounting for income taxes discussed above, none of the other provisions in this amended guidance had a material impact on our condensed consolidated financial statements.
Balance Sheet Classification of Deferred Taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. As a result, current deferred tax assets of $105,321 have been netted together with noncurrent deferred income tax liabilities on the March 31, 2017 consolidated condensed balance sheet. The prior period presented was not retrospectively adjusted.
Full Cost Pool Ceiling Test and Proved Undeveloped Reserves
As of March 31, 2017, our capitalized costs of oil and gas properties were substantially below the full cost valuation ceiling. We do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarter of fiscal 2017. However, persistent and substantially lower oil prices would have an effect on the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and could adversely impact our ceiling tests in future quarters. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to: the estimated future net cash flows from proved oil and gas reserves, discounted at 10%; plus the cost of any properties not being amortized; plus the lower of cost or fair value of unproved properties included in costs being amortized; less the income tax effect related to the differences between the book and tax basis of the properties (the full cost valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our petroleum products during the twelve month period ending with the balance sheet date. If commodity prices drop below the average from the past twelve months, future ceiling test calculations would be adversely affected. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future.
Our proved undeveloped reserves at June 30, 2016 in the Delhi field consisted primarily of the NGL plant and development of the remaining eastern part of the field. Remaining estimated capital expenditures amount to $8.12 per BOE for the Phase V expansion of the CO 2 flood in the undeveloped eastern part of the field, which is included in proved undeveloped reserves. Given the geology of the Delhi field, no remaining estimated capital expenditures are required to develop our probable or possible reserves as these reserves reflect incremental quantities associated with a greater percentage recovery of hydrocarbons in place than the recovery quantities assumed for proved reserves. In the current quarter our proved undeveloped NGL reserves were transferred to proved developed producing reserves as the completed NGL plant attained initial production of 830 gross BOEPD. We expect to achieve full production in our fiscal fourth quarter. The expanded development of the eastern part of the Delhi field was commenced upon the reversion of our working interest in November 2014. Shortly thereafter, the operator reduced its capital budget and temporarily postponed development of the eastern part of the Delhi field. Resumption of this development project is dependent, at least in part, on the operator's and our allocation of available capital to projects within their portfolio. At this time, despite lower commodity price levels, we continue to believe that these projects are economically viable and it is probable they will be executed within the next several years. We base our analysis on the current lifting costs in the field and the relatively low future development costs per BOE. Therefore, we believe these reserves remain properly classified as proved undeveloped reserves under SEC guidelines. See further discussion related to proved undeveloped reserves in our Annual Report on Form 10-K for the fiscal year ended June 30, 2016.
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Three Months Ended March 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:

| Three Months Ended March 31, |  |  |  |
| 2017 |  | 2016 |  | Variance |  | Variance %
Oil and gas production: |  |  |  |  |  |  |
Crude oil revenues | $ | 9,060,796 |  |  | $ | 5,005,955 |  |  | $ | 4,054,841 |  |  | 81.0 | %
NGL revenues | 464,641 |  |  | 597 |  |  | 464,044 |  |  | n.m. |
Natural gas revenues | — |  |  | 183 |  |  | (183 | ) |  | n.m. |
Total revenues | $ | 9,525,437 |  |  | $ | 5,006,735 |  |  | $ | 4,518,702 |  |  | 90.3 | %
Crude oil volumes (Bbl) | 183,811 |  |  | 166,881 |  |  | 16,930 |  |  | 10.1 | %
NGL volumes (Bbl) | 19,594 |  |  | 47 |  |  | 19,547 |  |  | n.m. |
Natural gas volumes (Mcf) | — |  |  | 145 |  |  | (145 | ) |  | n.m. |
Equivalent volumes (BOE) | 203,405 |  |  | 166,952 |  |  | 36,453 |  |  | 21.8 | %
Crude oil (BOPD, net) | 2,042 |  |  | 1,834 |  |  | 208 |  |  | 11.3 | %
NGLs (BOEPD, net) | 218 |  |  | 1 |  |  | 217 |  |  | n.m. |
Natural gas (BOEPD, net) | — |  |  | — |  |  | — |  |  | n.m. |
Equivalent volumes (BOEPD, net) | 2,260 |  |  | 1,835 |  |  | 425 |  |  | 23.2 | %
Crude oil price per Bbl | $ | 49.29 |  |  | $ | 30.00 |  |  | $ | 19.29 |  |  | 64.3 | %
NGL price per Bbl | 23.71 |  |  | 12.70 |  |  | 11.01 |  |  | 86.7 | %
Natural gas price per Mcf | — |  |  | 1.26 |  |  | (1.26 | ) |  | n.m. |
Equivalent price per BOE | $ | 46.83 |  |  | $ | 29.99 |  |  | $ | 16.84 |  |  | 56.2 | %
CO 2 costs | $ | 1,049,035 |  |  | $ | 831,485 |  |  | $ | 217,550 |  |  | 26.2 | %
All other lease operating expenses | 1,762,223 |  |  | 1,360,732 |  |  | 401,491 |  |  | 29.5 | %
Production costs | $ | 2,811,258 |  |  | $ | 2,192,217 |  |  | $ | 619,041 |  |  | 28.2 | %
Production costs per BOE | $ | 13.82 |  |  | $ | 13.13 |  |  | $ | 0.69 |  |  | 5.3 | %
CO 2 volumes (MMcf per day, gross) | 66.3 |  |  | 73.1 |  |  | (6.8 | ) |  | (9.3 | )%
Oil and gas DD&A (a) | $ | 1,515,368 |  |  | $ | 1,262,164 |  |  | $ | 253,204 |  |  | 20.1 | %
Oil and gas DD&A per BOE | $ | 7.45 |  |  | $ | 7.56 |  |  | $ | (0.11 | ) |  | (1.5 | )%
Artificial lift technology services: |  |  |  |  |  |  |
Services revenues | $ | — |  |  | $ | 100,000 |  |  | $ | (100,000 | ) |  | n.m. |
Cost of service | — |  |  | 10,933 |  |  | (10,933 | ) |  | n.m. |

n.m. Not meaningful.
(a) Excludes depreciation and amortization expense for artificial lift technology services and $8,107 and $6,636 of other depreciation and amortization expense for the three months ended March 31, 2017 and 2016, respectively.
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Net Income Available to Common Stockholders. For the three months ended March 31, 2017, we generated net income to common shareholders of $2.4 million, or $0.07 per diluted share, on total revenues of $9.5 million. This compares to a net loss of $0.3 million, or $0.01 per diluted share, on total revenues of $5.1 million for the year-ago quarter. The $2.7 million earnings increase reflects a $4.4 million revenue increase, $0.2 million of lower operating expenses and a $0.1 million decrease in allocated net income to holders of called preferred shares, partially offset by a $0.4 million decline in derivative gains and $1.6 million of higher income tax expense.
Oil and Gas Production. Revenues increased 90% to $9.5 million primarily as a result of a 22% increase in production volumes from the year-ago quarter, together with a 56% increase in realized prices from $29.99 per equivalent barrel to $46.83 per barrel in the current quarter. Until the current quarter, Delhi oil production revenues comprised virtually all of our revenues. Net Delhi oil production volumes of 2,042 BOPD increased 208 BOPD from a year ago as a result of production enhancement and conformance operations in the field. NGL revenues averaged 218 BOEPD as sales of production from the Delhi NGL plant commenced in the current quarter.
Production Costs. Production costs for the current quarter were $2.8 million, a $0.6 million, or 28%, increase from a year ago. Current cost includes $1.0 million for CO 2 costs, a 26% increase. Higher purchase cost per mcf, which is derived from the realized field oil price, was partially offset by a 10% decline in purchase volumes reflecting operational efficiencies. Average gross injection volumes decreased from 73.1 MMcf per day in the year-ago quarter to 66.3 MMcf per day for the current quarter. For the current quarter, production costs were $13.82 per BOE on total production volumes. Calculated solely on our Delhi working interest volumes, production costs were $18.42 per barrel, of which $7.11 per barrel was CO 2 cost. These costs per barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses decreased $1.0 million, or 44%, to $1.3 million for the three months ended March 31, 2017 due to a $1.0 million decrease in litigation costs.
Other Income and Expenses. For the three months ended March 31, 2017, aggregate income other items decreased $0.4 million from the year-ago quarter due to a decrease in net gains on derivative positions.
Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.3 million, or 20%, to $1.5 million for the current quarter compared to the year-ago period primarily due to higher full cost pool depletion reflecting a 21.8% increase in production to 203,405 BOE, partly offset by a 1.5% lower amortization rate of $7.45 per BOE.
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Nine Months Ended March 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:

| Nine Months Ended March 31, |  |  |  |
| 2017 |  | 2016 |  | Variance |  | Variance %
Oil and gas production: |  |  |  |  |  |  |
Crude oil revenues | $ | 25,184,468 |  |  | $ | 18,897,572 |  |  | $ | 6,286,896 |  |  | 33.3 | %
NGL revenues | 464,730 |  |  | 2,332 |  |  | 462,398 |  |  | n.m. |
Natural gas revenues | (4 | ) |  | 1,204 |  |  | (1,208 | ) |  | n.m. |
Total revenues | $ | 25,649,194 |  |  | $ | 18,901,108 |  |  | $ | 6,748,086 |  |  | 35.7 | %
Crude oil volumes (Bbl) | 544,628 |  |  | 489,644 |  |  | 54,984 |  |  | 11.2 | %
NGL volumes (Bbl) | 19,598 |  |  | 171 |  |  | 19,427 |  |  | n.m. |
Natural gas volumes (Mcf) | 16 |  |  | 634 |  |  | (618 | ) |  | (97.5 | )%
Equivalent volumes (BOE) | 564,229 |  |  | 489,921 |  |  | 74,308 |  |  | 15.2 | %
Crude oil (BOPD, net) | 1,988 |  |  | 1,780 |  |  | 208 |  |  | 11.7 | %
NGLs (BOEPD, net) | 71 |  |  | 1 |  |  | 70 |  |  | n.m. |
Natural gas (BOEPD, net) | — |  |  | — |  |  | — |  |  | n.m. |
Equivalent volumes (BOEPD, net) | 2,059 |  |  | 1,781 |  |  | 278 |  |  | 15.6 | %
Crude oil price per Bbl | $ | 46.24 |  |  | $ | 38.59 |  |  | $ | 7.65 |  |  | 19.8 | %
NGL price per Bbl | 23.71 |  |  | 13.64 |  |  | 10.07 |  |  | 73.8 | %
Natural gas price per Mcf | (0.25 | ) |  | 1.90 |  |  | (2.15 | ) |  | n.m. |
Equivalent price per BOE | $ | 45.46 |  |  | $ | 38.58 |  |  | $ | 6.88 |  |  | 17.8 | %
CO 2 costs | $ | 3,168,909 |  |  | $ | 3,238,076 |  |  | $ | (69,167 | ) |  | (2.1 | )%
All other lease operating expenses | 4,279,411 |  |  | 3,792,461 |  |  | 486,950 |  |  | 12.8 | %
Production costs | $ | 7,448,320 |  |  | $ | 7,030,537 |  |  | $ | 417,783 |  |  | 5.9 | %
Production costs per BOE | $ | 13.20 |  |  | $ | 14.35 |  |  | $ | (1.15 | ) |  | (8.0 | )%
CO 2 volumes (MMcf per day, gross) | 69.0 |  |  | 78.7 |  |  | (9.7 | ) |  | (12.3 | )%
Oil and gas DD&A (a) | $ | 4,080,818 |  |  | $ | 3,705,386 |  |  | $ | 375,432 |  |  | 10.1 | %
Oil and gas DD&A per BOE | $ | 7.23 |  |  | $ | 7.56 |  |  | $ | (0.33 | ) |  | (4.4 | )%
Artificial lift technology services: |  |  |  |  |  |  |
Services revenues | $ | — |  |  | $ | 207,960 |  |  | $ | (207,960 | ) |  | n.m. |
Cost of service | — |  |  | 70,932 |  |  | (70,932 | ) |  | n.m. |
Depreciation and amortization expense | $ | — |  |  | $ | 238,475 |  |  | $ | (238,475 | ) |  | n.m. |

n.m. Not meaningful.
(a) Excludes depreciation and amortization expense for artificial lift technology services and $23,606 and $14,783 of other depreciation and amortization expense for the nine months ended March 31, 2017 and 2016, respectively.
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Net Income Available to Common Stockholders. For the nine months ended March 31, 2017, we generated net income to common shareholders of $5.3 million, or $0.16 per diluted share, on total revenues of $25.6 million. This compares to net income of $3.3 million, or $0.10 per diluted share, on total revenues of $19.1 million for the corresponding prior year period. The $2.0 million earnings increase principally resulted from $6.5 million of higher revenue and $3.0 million of lower operating costs offset by a $4.0 million decrease in derivative gains, $1.1 million from a year-ago insurance recovery, a $0.7 million increase in allocated net income to holders of called preferred shares and $1.7 million of higher income taxes.
Oil and Gas Production. Revenues increased 34.2% to $25.6 million primarily as a result of a 15% increase in production volumes from the year-ago period together with a 18% increase in realized prices from $38.58 per equivalent barrel to $45.46 per barrel in the current period. Delhi production and revenues comprise virtually all of our revenues. Net Delhi oil production of 1,988 BOPD was 11.7% higher compared to the year-ago period as a result of production enhancement and conformance operations in the field and $0.5 million of initial current quarter plant NGL sales averaging 71 BOEPD over the nine months.
Production Costs. Production costs for the nine months ended March 31, 2017 were $7.4 million, a 6% increase from the year-ago period. CO 2 costs for the current period were $3.2 million, or 2% lower than the year-ago period, due to 13% lower purchase volumes as a result of operational efficiencies partially offset by a higher CO 2 price. The current period average gross CO 2 injection rate was 69.0 MMcf per day, compared to 78.7 MMcf per day in the year-ago period. For the current period, production costs were $13.20 per barrel on total production volumes. Calculated solely on our Delhi working interest volumes, production costs were $17.97 per barrel of which $7.74 per barrel was CO 2 cost. These latter production costs per barrel exclude production volumes from our royalty interests in the Delhi field which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses decreased $2.3 million, or 38%, to $3.8 million for the nine months ended March 31, 2017 from the year-ago period primarily due to a $2.0 million decrease in litigation costs and $0.4 million of lower salary and benefit expenses.
Other Income and Expenses. For the nine months ended March 31, 2017, aggregate other items decreased $5.1 million from the year-ago period due to a $4.0 million decrease in derivative gains and a year-ago $1.1 million gain from an insurance recovery at the Delhi field.
Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.1 million, or 4%, to $4.1 million for the nine months ended March 31, 2017 compared to the year-ago period as a result of $0.4 million of higher full cost pool depletion, partially offset by a $0.3 million decrease in fixed asset depreciation reflecting the prior year impairment of artificial lift equipment. Compared to the year-ago period, the slight increase in full cost pool amortization reflects a 15% production increase to 564,229 BOE substantially offset by a 4% lower amortization rate of $7.23 per BOE.
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 lease operating expenses and our capital expenditures. During fiscal 2017 to date, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties. General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas continues to exceed demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward.
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.
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Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements to report during the quarter ended March 31, 2017.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Information about market risks for the three months ended March 31, 2017, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2016.
Commodity Price Risk
Our most significant market risk is the pricing for crude oil, natural gas and NGLs. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, our 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 our ability to borrow and raise additional capital, as, if and when needed. We may use derivative instruments to manage our exposure to commodity price risk from time to time based on our assessment of such risk.
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, 2017 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended March 31, 2017 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.
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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 18 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2016 Annual Report. Material developments in the status of those proceedings during the quarter ended March 31, 2017 are described in Part I. Item 1. "Financial Information" under Note 15 — Commitments and Contingencies in this Quarterly Report and incorporated herein by reference. 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, 2016 includes a detailed description 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, 2016.
ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
During the quarter ended March 31, 2017, 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, 2017, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vestings of restricted stock and/or exercises of stock options.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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 Executive Officer
Date: May 9, 2017 |  |

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