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 ~~September 30, 2017~~March 31, 2018

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 ~~November 5, 2017,~~May 4, 2018, was ~~33,064,246.~~33,171,514.

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 ~~September 30, 2017~~March 31, 2018 and June 30, 2017	2
	Unaudited Consolidated Condensed Statements of Operations for the three and nine months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	3
	Unaudited Consolidated Condensed Statements of Cash Flows for the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	4
	Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the ~~three~~nine months ended ~~September 30, 2017~~March 31, 2018	5
	Notes to Unaudited Consolidated Condensed Financial Statements	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	2125

ITEM 4.	CONTROLS AND PROCEDURES	2125

PART II. OTHER INFORMATION		2326

ITEM 1.	LEGAL PROCEEDINGS	2326

ITEM 1A.	RISK FACTORS	2326

ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	2326

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	2326

ITEM 4.	MINE SAFETY DISCLOSURES	2426

ITEM 5.	OTHER INFORMATION	2426

ITEM 6.	EXHIBITS	2426

SIGNATURES		2427

PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)


	September 30, 2017		June 30, 2017		March 31, 2018		June 30, 2017
Assets
Current assets
Cash and cash equivalents	$	24,129,161	$	23,028,153	$	27,186,809	$	23,028,153
Receivables	3,027,283		2,726,702		3,949,973		2,726,702
Prepaid expenses and other current assets	291,376		387,672		682,645		387,672
Total current assets	27,447,820		26,142,527		31,819,427		26,142,527
Oil and natural gas property and equipment, net (full-cost method of accounting)	60,901,957		61,790,068		59,589,750		61,790,068
Other property and equipment, net	36,418		40,689		34,144		40,689
Total property and equipment	60,938,375		61,830,757		59,623,894		61,830,757
Other assets	277,926		295,384		243,011		295,384
Total assets	$	88,664,121	$	88,268,668	$	91,686,332	$	88,268,668
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	2,032,076	$	1,992,416	$	2,786,518	$	1,994,255
Accrued liabilities and other	634,642		726,478		628,663		724,639
State and federal income taxes payable	370,745		—
Total current liabilities	3,037,463		2,718,894		3,415,181		2,718,894
Long term liabilities
Senior secured credit facility (Note 13)					—		—
Deferred income taxes	15,845,804		15,826,291		10,754,077		15,826,291
Asset retirement obligations	1,275,207		1,253,628		1,319,291		1,253,628
Total liabilities	20,158,474		19,798,813		15,488,549		19,798,813
Commitments and contingencies (Note 15)
Commitments and contingencies (Note 14)
Stockholders’ equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,066,717 shares and 33,087,308 as of September 30, 2017 and June 30, 2017, respectively	33,066		33,087
Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of March 31, 2018 and June 30, 2017, respectively					33,171		33,087
Additional paid-in capital	41,338,709		40,961,957		41,890,553		40,961,957
Retained earnings	27,133,872		27,474,811		34,274,059		27,474,811
Total stockholders’ equity	68,505,647		68,469,855		76,197,783		68,469,855
Total liabilities and stockholders’ equity	$	88,664,121	$	88,268,668	$	91,686,332	$	88,268,668

See accompanying notes to consolidated condensed financial statements.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)


	Three Months Ended September 30,						Three Months Ended March 31,						Nine Months Ended March 31,
	2017			2016			2018			2017			2018			2017
Revenues
Crude oil	$	7,829,255		$	7,593,855		$	9,639,238		$	9,060,796		$	27,654,128		$	25,184,468
Natural gas liquids	708,616			89			610,328			464,641			2,200,220			464,730
Natural gas	—			(4		)	—			—			—			(4		)
Total revenues	8,537,871			7,593,940			10,249,566			9,525,437			29,854,348			25,649,194
Operating costs
Production costs	2,891,586			2,344,641			3,360,603			2,811,258			9,166,701			7,448,320
Depreciation, depletion and amortization	1,518,543			1,273,439			1,360,885			1,523,475			4,513,296			4,104,424
Accretion of discount on asset retirement obligations	21,579			13,224			22,263			13,562			66,865			39,892
General and administrative expenses *	1,569,704			1,235,043			1,842,548			1,283,906			5,078,508			3,760,348
Total operating costs	6,001,412			4,866,347			6,586,299			5,632,201			18,825,370			15,352,984
Income from operations	2,536,459			2,727,593			3,663,267			3,893,236			11,028,978			10,296,210
Other
Gain on realized derivative instruments, net	—			90			—			3,350			—			3,440
Loss on unrealized derivative instruments, net	—			(14,132		)
Gain on unrealized derivative instruments, net							—			47,965			—			33,833
Interest and other income	14,850			12,745			21,345			13,099			52,036			39,905
Interest expense	(20,455		)	(20,345		)	(30,525		)	(20,317		)	(71,436		)	(61,373		)
Income before income taxes	2,530,854			2,705,951			3,654,087			3,937,333			11,009,578			10,312,015
Income tax provision	390,322			889,176
Income tax provision (benefit)							585,733			1,518,190			(4,076,156		)	3,768,463
Net income attributable to the Company	2,140,532			1,816,775			3,068,354			2,419,143			15,085,734			6,543,552
Dividends on preferred stock	—			250,990			—			—			—			250,990
Deemed dividend on preferred shares called for redemption	—			1,002,440
Deemed dividend on redeemed preferred shares							—			—			—			1,002,440
Net income available to common stockholders	$	2,140,532		$	563,345		$	3,068,354		$	2,419,143		$	15,085,734		$	5,290,122
Earnings per common share
Basic	$	0.06		$	0.02		$	0.09		$	0.07		$	0.46		$	0.16
Diluted	$	0.06		$	0.02		$	0.09		$	0.07		$	0.45		$	0.16
Weighted average number of common shares
Basic	33,089,244			32,957,010			33,171,514			33,062,297			33,123,185			33,021,865
Diluted	33,147,508			33,007,599			33,191,312			33,115,699			33,155,870			33,064,708

* General and administrative expenses for the three months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ included non-cash stock-based compensation expense of ~~$487,484~~$352,420 and ~~$311,688,~~$291,151, respectively. For the corresponding nine month periods, non-cash stock-based compensation expense was $1,324,230 and $878,023, respectively.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended March 31,
	2017			2016			2018			2017
Cash flows from operating activities
Net income attributable to the Company	$	2,140,532		$	1,816,775		$	15,085,734		$	6,543,552
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,532,610			1,287,523			4,555,496			4,146,898
Stock-based compensation	487,484			311,688			1,324,230			878,023
Accretion of discount on asset retirement obligations	21,579			13,224			66,865			39,892
Settlements of asset retirement obligations	—			(15,899		)	—			(157,910		)
Deferred income taxes	19,513			708,673
Loss on derivative instruments, net	—			14,042
Deferred income taxes (benefit)							(5,072,214		)	3,079,342
Gain on derivative instruments, net							—			(37,273		)
Changes in operating assets and liabilities:
Receivables	(300,581		)	119,808			(1,223,271		)	(723,161		)
Prepaid expenses and other current assets	96,296			(21,365		)	(294,973		)	(445,597		)
Accounts payable and accrued expenses	(166,904		)	(2,235,240		)	73,678			(1,808,566		)
Income taxes payable	370,745			(524,772		)	—			(164,544		)
Net cash provided by operating activities	4,201,274			1,474,457			14,515,545			11,350,656
Cash flows from investing activities
Derivative settlement payments (paid) received	—			(318,708		)
Derivative settlement payments paid							—			(318,618		)
Capital expenditures for oil and natural gas properties	(508,042		)	(4,818,816		)	(1,668,820		)	(10,096,475		)
Capital expenditures for other property and equipment	—			(26,347		)	(6,033		)	(32,260		)
Net cash used in investing activities	(508,042		)	(5,163,871		)	(1,674,853		)	(10,447,353		)
Cash flows from financing activities
Cash dividends to preferred stockholders	—			(168,575		)	—			(250,990		)
Cash dividends to common stockholders	(2,481,471		)	(1,652,290		)	(8,286,486		)	(6,116,323		)
Common share repurchases, including shares surrendered for tax withholding	(110,753		)	(330,070		)	(395,550		)	(459,858		)
Redemption of preferred shares							—			(7,932,975		)
Other							—			32
Net cash used in financing activities	(2,592,224		)	(2,150,935		)	(8,682,036		)	(14,760,114		)
Net increase (decrease) in cash and cash equivalents	1,101,008			(5,840,349		)	4,158,656			(13,856,811		)
Cash and cash equivalents, beginning of period	23,028,153			34,077,060			23,028,153			34,077,060
Cash and cash equivalents, end of period	$	24,129,161		$	28,236,711		$	27,186,809		$	20,220,249


Supplemental disclosures of cash flow information:	Three Months Ended September 30,					Nine Months Ended March 31,
	2017		2016			2018			2017
Income taxes paid	$	—	$	787,366		$	1,456,754		$	1,383,773
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	114,729		(2,030,485		)	622,185			(3,181,640		)
Accrued redemption of called preferred shares	—		7,932,975
Accrued preferred dividends through redemption date	—		82,415
Oil and natural gas property costs incurred through recognition of asset retirement obligations						(778		)	14,119

See accompanying notes to consolidated condensed financial statements.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statement of Changes in Stockholders' Equity

For the ~~Three~~Nine Months Ended ~~September 30, 2017~~March 31, 2018

(Unaudited)


	Common Stock																	Common Stock
	Common Stock					Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity			Common Stock					Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
	Shares		Par Value			Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity			Shares		Par Value			Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance at June 30, 2017	33,087,308		$	33,087		$	40,961,957		$	27,474,811		$	—		$	68,469,855		33,087,308		$	33,087		$	40,961,957		$	27,474,811		$	—		$	68,469,855
Issuance of restricted common stock	14,254		14			(14		)	—			—			—			158,785		158			(158		)	—			—			—
Forfeitures of restricted stock	(19,561	)	(20		)	20			—			—			—			(19,561	)	(20		)	20			—			—			—
Common share repurchases, including shares surrendered for tax withholding	(15,284	)	—			—			—			(110,753		)	(110,753		)	(55,018	)	—			—			—			(395,550		)	(395,550		)
Retirements of treasury stock	—		(15		)	(110,738		)	—			110,753			—			—		(54		)	(395,496		)	—			395,550			—
Stock-based compensation	—		—			487,484			—			—			487,484			—		—			1,324,230			—			—			1,324,230
Net income attributable to the Company	—		—			—			2,140,532			—			2,140,532			—		—			—			15,085,734			—			15,085,734
Common stock cash dividends	—		—			—			(2,481,471		)	—			(2,481,471		)	—		—			—			(8,286,486		)	—			(8,286,486		)
Balance at September 30, 2017	33,066,717		$	33,066		$	41,338,709		$	27,133,872		$	—		$	68,505,647
Balance at March 31, 2018																		33,171,514		$	33,171		$	41,890,553		$	34,274,059		$	—		$	76,197,783

See accompanying notes to consolidated condensed financial statements.

Table of Contents

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"), together with 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 2017 Annual Report on Form 10-K for the fiscal year ended June 30, 2017, 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 may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depreciation, depletion and amortization 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.~~date, which for public business entities was for fiscal years beginning after December 31, 2016. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition onfor contracts with customers to transfer goods or services or onfor contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition onfor 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,~~business entities, 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.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal years beginning after

Table of Contents

Evolution Petroleum Corporation And Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

December 15, 2017. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

OnIn 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 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.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently, the Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows.

Note 2 — Receivables

As of ~~September 30, 2017~~March 31, 2018 and June 30, 2017, our receivables consisted of the following:


	September 30, 2017		June 30, 2017		March 31, 2018		June 30, 2017
Receivables from oil and gas sales	$	3,027,247	$	2,722,880
Receivables from oil and NGL sales					$	3,949,863	$	2,722,880
Other	36		3,822		110		3,822
Total receivables	$	3,027,283	$	2,726,702	$	3,949,973	$	2,726,702

Note 3 — Prepaid Expenses and Other Current Assets

As of ~~September 30, 2017~~March 31, 2018 and June 30, 2017, our prepaid expenses and other current assets consisted of the following:


	September 30, 2017		June 30, 2017		March 31, 2018		June 30, 2017
Prepaid insurance	$	113,554	$	169,416	$	31,269	$	169,416
Retainers and deposits	7,553		7,553		6,089		7,553
Prepaid federal and state income taxes	121,231		121,232		581,991		121,232
Other prepaid expenses	49,038		89,471		63,296		89,471
Prepaid expenses and other current assets	$	291,376	$	387,672	$	682,645	$	387,672

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Evolution Petroleum Corporation And Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 4 — Property and Equipment

As of ~~September 30, 2017~~March 31, 2018 and June 30, 2017, our oil and natural gas properties and other property and equipment consisted of the following:


	September 30, 2017			June 30, 2017			March 31, 2018			June 30, 2017
Oil and natural gas properties
Property costs subject to amortization	$	85,585,703		$	84,962,933		$	87,253,160		$	84,962,933
Less: Accumulated depreciation, depletion, and amortization	(24,683,746		)	(23,172,865		)	(27,663,410		)	(23,172,865		)
Unproved properties not subject to amortization	—			—			—			—
Oil and natural gas properties, net	$	60,901,957		$	61,790,068		$	59,589,750		$	61,790,068
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	$	135,377		$	135,377		$	141,410		$	135,377
Less: Accumulated depreciation	(98,959		)	(94,688		)	(107,266		)	(94,688		)
Other property and equipment, net	$	36,418		$	40,689		$	34,144		$	40,689

During the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017, the Company incurred capital expenditures of ~~$0.6~~$2.3 million ~~for~~and $6.9 million, respectively, in the Delhi field.

Note 5 — Other Assets

As of ~~September 30, 2017~~March 31, 2018 and June 30, 2017, other assets consisted of the following:


	September 30, 2017			June 30, 2017			March 31, 2018			June 30, 2017
Royalty rights	$	108,512		$	108,512		$	108,512		$	108,512
Less: Accumulated amortization of royalty rights	(23,737		)	(20,346		)	(30,519		)	(20,346		)
Investment in Well Lift Inc., at cost	108,750			108,750			108,750			108,750
Deferred loan costs	168,972			168,972			168,972			168,972
Less: Accumulated amortization of deferred loan costs	(84,571		)	(70,504		)	(112,704		)	(70,504		)
Other assets, net	$	277,926		$	295,384		$	243,011		$	295,384

~~The Company accounts for its~~Our royalty rights and investment in Well Lift, Inc. ~~using~~("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated the technology. We own 17.5% of the common stock of WLI and account for our investment under the cost ~~method under which~~method. Any dividends paid are recorded as income and any return of capital reduces our cost basis in the investment. Our investment ~~and any dividends paid are recorded as income. Investment value~~in WLI 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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Notes to Unaudited Consolidated Condensed Financial Statements

Note 6 — Accrued Liabilities and Other

As of ~~September 30, 2017~~March 31, 2018 and June 30, 2017, our other current liabilities consisted of the following:


	September 30, 2017		June 30, 2017		March 31, 2018		June 30, 2017
Accrued incentive and other compensation	$	143,802	$	413,113	$	412,439	$	413,113
Accrued severance payments	90,800		—
Asset retirement obligations due within one year	35,115		35,115		35,539		35,115
Accrued royalties, including suspended accounts	11,524		17,708		11,499		17,708
Accrued franchise taxes	191,362		150,062		124,299		150,062
Accrued ad valorem taxes	162,039		108,639		44,887		108,641
Other accrued liabilities	—		1,841
Accrued liabilities and other	$	634,642	$	726,478	$	628,663	$	724,639

Note 7 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we ~~will~~expect to 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 ~~three~~nine months ended ~~September 30, 2017~~March 31, 2018 and for the year ended June 30, 2017:


	September 30, 2017			June 30, 2017			March 31, 2018			June 30, 2017
Asset retirement obligations — beginning of period	$	1,288,743		$	962,196		$	1,288,743		$	962,196
Liabilities incurred	—			52,792			—			52,792
Liabilities settled	—			(157,164		)	—			(157,164		)
Liabilities sold	—			(47,817		)	—			(47,817		)
Accretion of discount	21,579			59,664			66,865			59,664
Revision of previous estimates	—			419,072			(778		)	419,072
Asset retirement obligations — end of period	$	1,310,322		$	1,288,743		$	1,354,830		$	1,288,743
Less current portion in accrued liabilities	(35,115		)	(35,115		)	(35,539		)	(35,115		)
Long-term portion of asset retirement obligations	$	1,275,207		$	1,253,628		$	1,319,291		$	1,253,628

Note 8 — Stockholders’ Equity

Common Stock

As of ~~September 30, 2017,~~March 31, 2018, we had ~~33,066,717~~33,171,514 shares of common stock outstanding.

~~Effective December 31, 2013, the Board of Directors initiated a~~The Company began paying quarterly cash ~~dividend~~dividends on ~~our~~ common stock at the rate of $0.10 per share per quarter. The rate was subsequently adjusted to $0.05 per share for the dividend payments from March 31, 2015 to September 30, 2016. During fiscal year 2017, the Board 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 and June 30, 2017 dividend payments. The Board made a further increase to $0.075 per share for the September 30, 2017 dividend payment.

2013. We paid ~~cash~~ dividends of ~~$2,481,471 ($0.075 per share)~~$8,286,486 and ~~$1,652,290 ($0.05 per share)~~$6,116,323 to our common shareholders during the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. The following table reflects the dividends paid in each quarter within the respective nine month periods:



	Fiscal Year
	2018		2017
Third quarter ended March 31,	$	0.100	$	0.070
Second quarter ended December 31,	$	0.075	$	0.065
First quarter ended September 30,	$	0.075	$	0.050

OnIn 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~~Between June 2015 and December 2015, the Company spent $1,609,008 to repurchase 265,762 common shares at an average price of $6.05 per share. There have been no shares repurchased in the open market since ~~mid-December~~December 2015. Under

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~~Notes to Unaudited Consolidated Condensed Financial Statements~~

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

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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 ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ the Company acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll ~~taxes paid in the quarter.~~tax withholding obligations. The treasury shares were subsequently canceled. Such shares were valued at fair market value on the date of ~~vesting. The treasury shares were subsequently canceled.~~vesting, as reflected in the following table:


	Three Months Ended September 30,				Nine Months Ended March 31,
	2017		2016		2018		2017
Number of treasury shares acquired	15,284		58,147		55,018		73,455
Average cost per share	$	7.25	$	5.68	$	7.19	$	6.26
Total cost of treasury shares acquired	$	110,753	$	330,070	$	395,550	$	459,858

Series A Cumulative Preferred Stock Called for Redemption

OnIn September ~~30,~~ 2016, the Company announced the decision to redeem all 317,319 outstanding shares of its 8.5% Series A Cumulative Preferred Stock. The redemption occurred onin November ~~14,~~ 2016 at the stated value of $25.00 per share plus all accumulated and unpaid distributions, for an aggregate redemption cost of $7,932,975.

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.

Dividends on the Series A Cumulative Preferred Stock were paid at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly. During the ~~three~~nine months ended ~~September 30,~~March 31, 2016, we paid cash dividends of ~~$168,575~~$250,990 to holders of our Series A Preferred Stock ~~and accrued $82,415 of remaining dividends which were paid on~~prior to the November 2016 redemption date.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2017, 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, 2018, we expect all common dividends for such period to be treated as qualified dividend income. Such projections are based on our reasonable expectations as of ~~September 30, 2017~~March 31, 2018 and are subject to change based on our final tax calculations at the end of the fiscal year.

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 ~~September 30, 2017, 1,100,000~~March 31, 2018, 987,845 shares ~~were~~remained available for grant under the 2016 Plan.

At ~~September 30, 2017,~~December 8, 2016, there were no shares available for future grants under the 2004 Plan. 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 outstanding grants of restricted common stock awards ("Restricted Stock"), and contingent restricted common stock awards ("Contingent Restricted Stock") to employees and directors of the Company.

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Restricted Stock and Contingent Restricted Stock

Prior to August 28, 2014, all Restricted Stock grants contained a four-year vesting period based on service. Restricted Stock which vests based 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~~The Company ~~awarded~~awards grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants ~~were~~are issued on the date of ~~grant, whereas the~~grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan ~~but will be issued only upon~~they were granted under.

Service-based awards vest with continuous employment by the ~~attainment~~Company, generally in annual installments over a four-year period. Certain awards may contain other vesting periods, including quarterly installments and one-year vesting. Restricted Stock grants which vest based on service are valued at the fair market value on the date of ~~specified~~grant and amortized over the service period. During the nine months ended March 31, 2018, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employees and 66,944 awards to directors, substantially all of which have a one-year vesting period. We did not grant any performance-based or ~~market-based vesting provisions.~~market based awards, nor any Contingent Restricted Stock awards, during this period.

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 ~~September 30, 2017,~~March 31, 2018, 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~~would be recorded at that time and amortization would continue over the remaining expected vesting period.

Market-based awards ~~granted in fiscal 2017 entitle employees to~~ vest ~~in a fixed number of shares when~~if the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of ~~an index~~indices consisting of ~~sixteen designated~~either peer companies or a broad market index of companies in our industry with comparable market capitalizations on defined measurement dates. Market-based awards granted in fiscal 2015 and 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 companies comprising the SIG Exploration and Production Index (NASDAQ EPX) on defined measurement dates.industry. The fair ~~value~~values and expected vesting ~~period~~periods of these awards ~~were~~are 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 fiscal year ended June 30, 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 or director 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 ~~September 30, 2017~~March 31, 2018 consisted of the following:


	Number of Restricted Shares	Weighted Average Grant-Date Fair Value		Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	165,504	$	6.98	218,615	$	6.64
Performance-based awards	50,360	5.67		50,360	5.67
Market-based awards	115,111	4.96		50,359	5.44
Unvested Restricted Stock at September 30, 2017	330,975	$	6.08
Unvested Restricted Stock at March 31, 2018				319,334	$	6.30

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2018:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at March 31, 2018		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	391,624		$	6.22
Service-based shares granted	112,155		6.96
Vested	(164,884	)	6.57
Forfeited	(19,561	)	6.16
Unvested Restricted Stock at March 31, 2018	319,334		$	6.30	$	1,184,557	1.25

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~~The following table sets forth the Restricted Stock transactions for the three months ended September 30, 2017:~~

Number of
Restricted
Shares Weighted
Average
Grant-Date
Fair Value Unamortized Compensation Expense at September 30, 2017 Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017 391,624
$ 6.22

Vested (41,088 ) 7.37

Forfeited (19,561 ) 6.16

Unvested Restricted Stock at September 30, 2017 330,975
$ 6.08
$ 1,101,876
1.87

Unvested Contingent Restricted Stock awards at ~~September 30, 2017~~March 31, 2018 consisted of the following:


	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value		Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	36,688	$	7.04	36,688	$	7.04
Market-based awards	57,556	3.14		25,180	3.42
Unvested contingent shares at September 30, 2017	94,244	$	4.66
Unvested contingent shares at March 31, 2018				61,868	$	5.57

The following table sets forth Contingent Restricted Stock transactions for the ~~three~~nine months ended ~~September 30, 2017:~~March 31, 2018:


	Number of Contingent Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at September 30, 2017 (1)		Weighted Average Remaining Amortization Period (Years)	Number of Contingent Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at March 31, 2018 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	113,270		$	4.64				113,270		$	4.64
Vested	(14,254	)	4.26					(46,630	)	3.34
Forfeited	(4,772	)	5.30					(4,772	)	5.30
Unvested contingent shares at September 30, 2017	94,244		$	4.66	$	53,155	1.74
Unvested contingent shares at March 31, 2018								61,868		$	5.57	$	57,231	.91

(1) Excludes ~~$258,430~~$115,665 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 ~~September 30,~~March 31, 2018 and 2017 was $352,420 and ~~2016~~$291,151, respectively. For the corresponding nine month periods, non-cash stock compensation expense was ~~$487,484~~$1,324,230 and ~~$311,688,~~$878,023, respectively.

Note 10 — Derivatives

InAs of June ~~2015,~~30, 2017 and March 31, 2018, the Company ~~began using~~had no derivative asset or liability positions.

From time to time, the Company has used and may in the future use derivative instruments to reduce its exposure to crude oil or other commodity price volatility ~~for a substantial portion~~ of its near-term forecasted production. The Company's objectives ~~for this program were~~are to achieve a more predictable level of cash flows to support the Company’s capital expenditure ~~program~~programs and to provide better financial visibility for ~~the payment of dividends on common stock.~~its other financial commitments. The Company ~~uses~~may use both fixed price swap agreements and costless collars to manage its exposure to crude oil and other commodity 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 Hedging ("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.~~other non-operating income and expense. Given the cost and complexity, ~~considerations,~~ the Company ~~did~~has elected not ~~elect~~ to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, ~~the effective~~a portion of the change in fair value of the derivative instruments, if effective in hedging the underlying commodity risk, would be deferred in other comprehensive income and ~~not~~ recognized in earnings ~~until~~only when 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

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~~Notes to Unaudited Consolidated Condensed Financial Statements~~

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. ~~At June 30, 2017, the Company had no derivative asset or liability positions. At September 30, 2017 and 2016, the Company held no derivative asset or liability positions.~~

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.

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Notes to Unaudited Consolidated Condensed Financial Statements

For the ~~three~~nine months ended ~~September 30, 2017,~~March 31, 2018, the Company had no gains or losses from derivatives. For the ~~three~~nine months ended ~~September 30, 2016,~~March 31, 2017, the Company recorded ~~in its consolidated statement of operations~~ a ~~loss~~gain on derivative instruments of ~~$14,042~~$37,273 consisting of ana realized gain of ~~$90~~$3,440 on settled positions and an unrealized ~~net loss~~gain of ~~$14,132 on unsettled positions.~~$33,833.

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.~~

~~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.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable timing of tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ending June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.

Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation of our income tax expense were approximately 18% and 37% for the nine months ended March 31, 2018 and 2017, respectively. After adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities at December 31, 2017, the effective rate for the nine months ended March 31, 2018 was a negative tax rate (benefit) of (37)% of income before income taxes.

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 significantly lower than the statutory federal rate as a result of percentage depletion in excess of basis and the tax effects of stock-based compensation, partially offset by state income taxes net of the federal benefit. Our quarterly income tax provisions are based on our reasonable estimates of income taxes payable at the end of the year. These estimates and our estimated interim effective tax rates may change significantly as additional financial results and amounts of capital spending become available during the year. In particular, our estimates of the utilization of excess percentage depletion, which is limited to 65% of actual taxable income, are subject to greater fluctuations between interim periods than other components of our tax provision.

There were neither unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during any periods presented in the ~~three months ended September 30, 2017.~~financial statements. 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, 2014 through June 30, ~~2016~~2017 for federal tax purposes and for the years ended June 30, 2013 through June 30, ~~2016~~2017 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 $390,322 and $889,176 for the three months ended September 30, 2017 and 2016, respectively, with corresponding effective tax rates of 15% and 33%. 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 three months ended September 30, 2017 was significantly lower than the statutory federal rate as a result of percentage depletion in excess of basis and the tax effects of stock-based compensation, partially offset by state income taxes net of federal benefit. Our quarterly income tax provisions are based on our reasonable estimates of income taxes payable at the end of the year. These estimates involve uncertainties and our estimated interim effective tax rates may change as additional financial results become available during the year. In particular, the utilization of excess percentage depletion is limited to 65% of actual taxable income and is subject to greater uncertainty than other components of our tax provision.

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Notes to Unaudited Consolidated Condensed Financial Statements

Note 1312 — Net Income Per Share

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


	Three Months Ended September 30,				Three Months Ended March 31,				Nine Months Ended March 31,
	2017		2016		2018		2017		2018		2017
Numerator
Net income available to common shareholders	$	2,140,532	$	563,345	$	3,068,354	$	2,419,143	$	15,085,734	$	5,290,122
Denominator
Weighted average number of common shares — Basic	33,089,244		32,957,010		33,171,514		33,062,297		33,123,185		33,021,865
Effect of dilutive securities:
Contingent restricted stock grants	58,264		28,845		19,798		27,216		32,685		17,860
Stock options	—		21,744		—		26,186		—		24,983
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,147,508		33,007,599
Weighted average number of common shares and potentially dilutive common shares used in diluted EPS					33,191,312		33,115,699		33,155,870		33,064,708

Net income per common share — Basic	$	0.06	$	0.02	$	0.09	$	0.07	$	0.46	$	0.16
Net income per common share — Diluted	$	0.06	$	0.02	$	0.09	$	0.07	$	0.45	$	0.16

Outstanding potentially dilutive securities as of ~~September 30, 2017~~March 31, 2018 were as follows:

Outstanding potentially dilutive securities as of ~~September 30, 2016~~March 31, 2017 were as follows:


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		At September 30, 2016	Weighted Average Exercise Price		At March 31, 2017
Contingent Restricted Stock grants	$	—	113,270	$	—	113,270
Stock Options	2.19		35,231	2.19		35,231
Total outstanding potentially dilutive securities	$	0.52	148,501	$	0.52	148,501

Note 1413 — 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 borrowing base under the Facility ~~has been~~was originally set at ~~$10,000,000.~~$10 million and was subsequently increased to $40 million effective February 1, 2018. As of ~~September 30, 2017,~~March 31, 2018, 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 under the Facility, 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.

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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 ~~$84,401~~$56,268 as of ~~September 30, 2017.~~March 31, 2018.

Note 1514 — 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~~We vigorously defended the ~~Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership~~claims. Based on our assessment of the ~~property in question along with its ownership~~continuing costs 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 March 2018. 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 todefending the Company in this ~~matter~~litigation, we entered into a confidential settlement agreement and obtained a full release and dismissal of all claims asserted in this matter. Although the agreement is confidential, the amount of the settlement payment, which was recorded in general and administrative expense as of March 31, 2018 and paid by the Company in April, is not material to ~~be remote.~~the financial position of the Company.

Lease Commitments. We have a non-cancelable operating lease for office space that expires on May 31, 2019. Future minimum lease commitments as of ~~September 30, 2017~~March 31, 2018 under this operating lease are as follows:

Twelve months ended September 30,
2018 $ 73,073
2019 $ 66,984



Twelve month periods ended March 31,
2019	$	73,073
2020 (through May)	$	12,179

Rent expense for the three months ended ~~September 30,~~March 31, 2018 and 2017 was $18,568 and ~~2016~~$14,656, respectively. Rent expense for the nine months ended March 31, 2018 and 2017 was ~~$19,851~~$57,617 and ~~$34,856,~~$68,081, respectively.

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, 2017 (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. Certain dollar amounts and percentages in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Quarterly Report on Form 10-Q have been rounded for presentation, and certain amounts may not sum due to rounding.

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 2017 Annual Report on Form 10-K for the year ended June 30, 2017 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 with low or minimal leverage, 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.~~stockholders. By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this ownership helps ensure that the interests of our employees and directors are aligned with our shareholders.

Our strategy is to maximize the value realized by our stockholders from our assets, particularly our core Delhi asset.

Highlights for our ~~First~~Third Quarter of Fiscal 2018 and Operations Update

"Current quarter" refers to the three months ended ~~September 30, 2017,~~March 31, 2018, the Company's ~~first~~third quarter of fiscal 2018.

"Prior quarter" refers to the three months ended ~~June 30,~~December 31, 2017, the Company's ~~fourth~~second quarter of fiscal ~~2017.~~2018.

"Year-ago quarter" refers to the three months ended ~~September 30, 2016,~~March 31, 2017, the Company's ~~first~~third quarter of fiscal 2017.

~~Key Points~~

~~Net~~

Highlights for the Quarter:

Current quarter net income was ~~$2.1~~$3.1 million, ~~in the first quarter of 2018,~~ or ~~$0.06~~$0.09 per ~~diluted~~ common share, compared to net income of ~~$0.6 million, or $0.02~~$0.07 per common ~~diluted~~ share in the ~~year ago quarter and net income of $1.5 million, or $0.05 per diluted share in the prior quarter.~~

~~Revenues for the fiscal first quarter of 2018 were $8.5 million, an increase of 12% over the year ago quarter and 3% below the prior quarter.~~

~~Lifting costs per unit at Delhi were $15.06 per equivalent barrel, which represents a 9.2% decrease over the prior quarter and a 14.4% increase over the~~ year-ago quarter.

~~The Company~~We paid ~~its sixteenth~~our eighteenth consecutive quarterly cash dividend on common shares, in the increased amount of ~~$0.075~~$0.10 per ~~share.~~share, and declared our nineteenth quarterly dividend of $0.10 per share payable in June 2018.

We commenced the planned twelve-well infill drilling program in the Delhi field in late March 2018.

~~The Company~~Our realized oil price for the current quarter was $63.56 per barrel, our highest quarterly average price since the quarter ended December 31, 2014.

We reported revenues of $10.2 million for the current quarter, a decrease of 7% from the prior quarter and an 8% increase over the year-ago quarter. Revenues and production were adversely impacted by abnormal sub-freezing weather in January 2018.

We ended the current quarter with ~~$24.4~~$28.4 million of working capital, ~~substantially all~~an increase of ~~which was cash. Our working capital increased by $1.0~~$0.8 million from the prior quarter, ~~despite~~after paying ~~$2.5~~$3.3 million in common stock ~~dividends during the quarter.~~dividends.

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, 2017.

Delhi Field - Enhanced Oil Recovery Project

~~Gross oil production at Delhi~~Our interests in the ~~first quarter~~Delhi field consist of ~~fiscal 2018 averaged 6,912 BOEPD, an 8.3% decrease from the prior quarter~~a 23.9% working interest (with associated 19.0% net revenue interest) and separate overriding royalty and mineral interests of 7.2%. This yields a ~~6.3% decrease from the year-ago quarter reflecting a reduced rate~~total net revenue interest of ~~spending in~~26.2%. The field is operated by Denbury Resources, Inc. (the "operator").

As previously reported, the field ~~and higher decline rates from certain conformance projects over the past~~had two ~~years. Some of the projects completed~~weather-related disruptions to operations in ~~2016 added higher than expected flush~~January 2018 due to abnormal sub-freezing temperatures. Consequently, both oil ~~production~~ and ~~have stabilized at lower rates during 2017.~~

~~Gross NGL sales for this quarter of production were 1,047 BOEPD, up slightly from 1,019 BOEPD in the prior quarter.~~ NGL production rates ~~have been impacted by~~suffered from multiple days of shut-ins in addition to scheduled downtimes for maintenance and other repairs both ~~planned and unplanned downtime~~ in the field and at the ~~central~~NGL plant. However, gross production ~~facilities. In early August,~~in February and March returned to normal levels of approximately 7,000 barrels of oil per day and 1,100 barrels of NGL's per day. The Company's net share of production for the ~~plant~~quarter was ~~shut-in~~1,685 BOPD and 199 barrels of NGL's per day.

Our net realized oil pricing in the current quarter improved to $63.56 per barrel from $57.30 per barrel in the prior quarter. This was based on an average WTI price of $62.89 per barrel for ~~four days in order~~the quarter. We continued to ~~perform capital modifications to~~receive a premium price for our crude oil based on Louisiana Light Sweet ("LLS") pricing, but the ~~inlet of the recycle facility.~~ Results from the NGL plant subsequent to completion of this project have been positive, with the plant operating at or near maximum capacity and efficiency. We expect gross NGL production to average 1,200 BOEPD or higherLLS differential narrowed during the ~~next two quarters.~~ ~~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~~quarter, as did our overall premium 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.~~WTI.

Production from the NGL plant is transported by truck to a processing 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, processing fees and processing fees. There may also be an additional deduction for NGL's that do not meet the purchaser's required specifications. We are working with the operator to better attain the purchaser's specification and seek a solution to minimize or eliminate sales of off-spec NGL production. Theother deductions. Our current mix of products contains a large percentage ~~(over 65%~~(~70%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's ~~has improved significantly over~~during the ~~past six months and the ratio of~~quarter was favorable, with net realized NGL ~~pricing to WTI pricing is~~prices averaging approximately ~~sixty percent (~60%).~~54% of WTI prices. NGL demand often has a seasonal pattern and prices tend to be higher during the cooler months of October through March. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we expect such volatility to continue.

Field operating expenses were ~~$15.06~~$19.82 per barrel of oil equivalent ("BOE") in the current quarter compared to ~~$16.59~~$14.30 in the prior quarter. This temporary increase in lifting costs is primarily attributable to the decrease in oil and NGL production as a direct result of the sub-freezing weather in January, and an overall 15% increase in CO₂expenses resulting from an 11% increase in realized oil prices and higher purchased CO₂ volumes. Our ~~net share of first quarter~~total lease operating expenses in the Delhi field were ~~$2.9~~$3.4 million in the current quarter, ~~which was $0.5~~increasing by $0.4 million ~~lower than~~from the prior quarter, and $0.5 million over the ~~year ago~~year-ago quarter. ~~The decline from the prior quarter was primarily due to lower CO~~₂ ~~cost and other field operating expenses, while NGL plant operating expenses were essentially flat. The decrease in CO~~₂ cost, which is tied directly to realized field oil prices, was primarily due to an 18% decrease in volume, as purchases decreased from 85.1 MMcf per day in the prior quarter to 69.3 MMcf per day in the current quarter. Calculated on total net production volumes, our totalOur purchased CO₂ costs ~~were $5.67~~increased to $1.5 million ($8.61 per ~~equivalent barrel in the current quarter compared to $6.41~~BOE) from $1.3 million ($6.21 per BOE) in the prior quarter and $1.0 million ($5.16 per BOE) in the year-ago quarter. Compared to the prior and year-ago quarter, purchased CO₂ volumes increased 6% and 14% , respectively, while our costs per Mcf increased as a result of higher realized oil prices in the field, which are directly tied to the price per Mcf for purchased CO₂. Under our contract with the operator, purchased CO₂ is priced at 1% of the realized oil price in the field per thousand cubic feet (“Mcf”), plus sales taxes of 8% ~~plus~~and transportation costs of $0.20 per Mcf. Our other (non CO₂) lease operating expenses were $1.9 million, up 15% from $1.6 million in the prior quarter, primarily due to higher workover expenses.

~~Our interests~~The operator commenced the twelve-well infill drilling program in the Delhi field ~~consist~~in late March as scheduled. Two wells have been drilled and a third well has been spudded in this program that is planned to be completed by late July 2018, along with the other nine wells. The operator has also started the construction of ~~a 23.9% working interest (with associated 19.0% net revenue interest)~~flowlines and ~~separate royalty interests~~facilities and expects to have the first wells online by the end of ~~7.2%.~~May 2018. This ~~yields a total net revenue interest~~infill program targets productive oil zones in the developed area of ~~26.2%.~~the field that the operator believes are not being swept effectively by the current CO₂ flood. This program is expected to both add production and increase ultimate recoveries above the current proved producing oil reserves.

~~Remaining estimated~~

2017 Tax Cuts and Jobs Act

On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital ~~expenditures~~investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ended June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our ~~proved undeveloped reserves amount~~liability for deferred income taxes to ~~$14.1 million, or $6.71 per BOE, consisting~~the lower rate in the Tax Act. This benefit was recognized in the quarter ended December 31, 2017. The accounting for the effects of ~~$3.2~~the rate change on the Company’s deferred tax balances was complete as of December 31, 2017 and no provisional amounts were recorded.



	Three Months Ended March 31,				Nine Months Ended March 31,
	2018		2017		2018			2017
Income before income taxes	3,654,087		3,937,333		11,009,578			10,312,015
Income tax (benefit) provision	585,733		1,518,190		(4,076,156	)	(a)	3,768,463
Effective tax rate	16	%	39	%	(37	)%	(b)	37	%

(a) The income tax provision for the nine months ended March 31, 2018 includes a one-time non-cash benefit of approximately $6.0 million for the ~~infill drilling project, $2.8~~adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. This discrete adjustment results in a negative tax rate (benefit) for this period.

(b) Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate together with any discrete items. For the nine months ended March 31, 2018, the effective rate used in the calculation of our income tax expense was approximately 18%. Applying this rate together with the $6.0 million discrete revaluation benefit resulted in the negative tax rate (benefit) of (37)%.

The effective tax rates for ~~Phase V infrastructure~~the three months and ~~$8.1~~the nine months ended March 31, 2018, excluding the impact of the $6.0 million for Phase V pattern development. No remaining 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 placedeferred tax adjustment, were lower than the ~~recovery percentage assumed for proved reserves. Looking forward, the timing of plans for continued development~~corresponding prior periods as a result of the ~~eastern part~~lower statutory tax rate and higher utilization of percentage depletion in excess of basis during the Delhi field is dependent on the operator’s plans for capital allocation within their portfolio. We continue to believe that this high quality and economically viable project will be executed as planned, subject to oil price volatility.

current year.

Liquidity and Capital Resources

We had ~~$24.1~~$27.2 million and $23.0 million in cash and cash equivalents at ~~September 30, 2017~~March 31, 2018 and June 30, 2017, respectively.

In addition, we ~~had $10 million of availability under our~~have a 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"~~(the "Facility") with ~~MidFirst Bank.~~a maximum capacity of $50.0 million. The Facility ~~provides a senior secured revolving credit facility with a~~had $40.0 million of undrawn borrowing base ~~of $10 million (the “Borrowing Base”) and a maximum borrowing amount of $50 million. The borrowing base is subject to periodic redeterminations and adjustments from time to time and has~~availability on March 31, 2018. There have been ~~set by mutual agreement at a level below our maximum borrowing capacity. The~~no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets. ~~It bears~~

Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. ~~There have been no borrowings under the Facility.~~

The Facility contains ~~certain~~ covenants ~~which, among other things,~~that require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than ~~$40~~$40.0 million, each as defined in the Facility. The Facility also contains other affirmative and negative covenants and events of default. As of ~~September 30, 2017,~~March 31, 2018, the Company was in compliance with all covenants contained in the ~~Facility, and no amounts were outstanding under the~~ Facility.

During the ~~three~~nine months ended ~~September 30, 2017,~~March 31, 2018, we funded our operations and cash dividends with cash generated from operations and ~~and~~ our cash balance increased $4.2 million during that period. ~~At September 30, 2017,~~As of March 31, 2018, our working capital was ~~$24.4~~$28.4 million, ~~compared to~~an increase of $5.0 million over working capital of $23.4 million at June 30, ~~2016.~~2017.

We have historically funded our operations through cash from operations and working capital. Our primary source of cash ~~has resulted from~~is the sale of oil and natural gas liquids production. A portion of these cash flows ~~were~~are used to fund our capital expenditures. While we expect to continue to expend capital to further develop the Delhi field, we and the operator have flexibility as to when this capital is spent. ~~Certain projects were recently electively delayed by the operator based on their funds available for capital spending in the current oil price environment.~~ The Company expects to manage future development activities in the Delhi field within the boundaries of its operating cash flow and existing working capital.

We may choose to evaluate and pursue new growth opportunities through acquisitions or other transactions. In addition to our cash on hand, we have access to at least $40.0 million of availability under our senior secured credit facility. In addition we have an effective shelf registration statement with Securities and Exchange Commission under which we may issue new debt or equity securities. If we choose to pursue new growth opportunities, 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.

Our other significant use of cash is our on-going dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid eighteen consecutive quarterly dividends. Distribution 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 February 2018, the Board declared an increase in the quarterly common stock dividend from $0.075 per share to $0.10 per share, effective with the dividend payment in March 2018 and declared a $0.10 per share dividend payable on June 29, 2018. The Board reviews the quarterly dividend rate in light of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing of further expansion of Delhi development and other potential growth opportunities.

Capital Budget - Delhi Field

During the ~~three~~nine months ended ~~September 30, 2017,~~March 31, 2018, we incurred ~~$0.6~~$2.3 million of capital expenditures at ~~Delhi, which includes $0.3~~Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, ~~to resolve issues with~~$0.9 million for CO₂ conformance projects and capital maintenance, $0.7 million for Test Site 5 infrastructure in the ~~NGL plant~~eastern portion of the field, and $0.3 million for ~~three capital workover conformance projects.~~the infill drilling program.

AnThe twelve-well infill drilling program ~~is planned for~~in the ~~second half of fiscal~~Delhi field commenced March 2018 ~~with~~and has an estimated net cost of ~~$3.2~~$4.7 million. ~~This~~The majority of these costs are expected to be incurred in the fourth quarter of this fiscal year and the remainder will continue into the first quarter of fiscal 2019. The operator estimates it will take up to five months to drill and complete all the wells. The program ~~will consist~~consists of ~~three~~five new CO₂ injection wells and ~~five~~seven new production wells and ~~will target~~targets productive oil zones which we believe are not being swept effectively by the current CO₂ flood. ~~This infill program~~It is expected to both add production and increase ultimate recoveries above the current ~~proved~~developed producing oil reserves. It is possible that the infill program may be expanded from eight to twelve wells based on capital available and potential economic opportunity. These additional wells, if drilled, would add approximately $1.6 million to our net cost.

We have ~~identified and~~also approved additional net capital expenditures ~~over the next~~for fiscal ~~year~~2018 totaling $2.8 million for water injection, flowlines and other infrastructure projects in preparation for the ~~Phase V pattern~~Test Site 5 development. Approximately $0.7 million of these costs have been incurred as of March 31, 2018. In addition, ~~there will likely~~we expect to continue to beperform conformance workover projects and will likely incur additional maintenance capital ~~expenditures that~~expenditures. Such amounts cannot be estimated accurately at this ~~time. The amount of these projects is~~time, but are not expected to be material to our financial position.

With the NGL plant completed, there are two remaining capital project phases planned to exploit the eastern part of the Delhi field. The first phase of this project, Phase V, was underway in the fall of 2014, immediately after reversion of our working interest. However, based on the decline in oil prices, the operator significantly reduced its capital budget and suspended work on this phase. The project was further deferred until the NGL plant was completed. The resumption of this project is dependent on prevailing oil prices, the availability of capital for such projects and the relative economics of this project. We believe this Phase V project, which has an estimated total cost of $10.9 million net (inclusive of the $2.8 million discussed above) to our working interest, has favorable economics, even in this lower price environment, and, based on discussions with the operator, expect the related expansion of the CO₂ flood to resume in fiscal 2019. The last phase of the project, Phase VI, has less favorable economics and will require a significant increase in oil prices or other improvements to the economics of the project before it is expected to move forward.

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 ~~$4.2~~$14.5 million and ~~$1.5~~$11.4 million for the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. The ~~$2.7~~approximate $3.2 million increase in cash provided by operations between these two ~~quarters was due to $0.3~~periods resulted from $8.5 million of higher net income and a ~~$2.7~~$1.7 million ~~decrease~~increase in cash ~~used~~provided by operating assets and liabilities, partially offset by a ~~$0.3~~$7.1 million decrease in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations. ~~The~~This decrease ~~in cash used by operating assets~~includes a $6.0 million one-time adjustment of our deferred income tax liability to the lower corporate tax rate under the 2017 Tax Cuts and ~~liabilities is primarily due to a reduction in Delhi joint interest billings outstanding that occurred early in the first quarter of fiscal 2017.~~Jobs Act.

Net cash used in investing activities was ~~$0.5~~$1.7 million and ~~$5.2~~$10.4 million for the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. The decrease in cash ~~outflow~~outflows was primarily due to ~~$4.3~~$8.4 million of lower capital expenditures together with a $0.3 million decline in derivative settlement payments. The prior year period included significant capital spending on the NGL plant, which was completed in January 2017.

Net cash used by financing activities for the ~~three~~nine months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ was ~~$2.6~~$8.7 million and ~~$2.2~~$14.8 million, respectively. The ~~$0.4~~$6.1 million ~~increase~~decrease in cash used was principally due to ~~the $0.8~~$7.9 million ~~increase~~disbursed in the prior fiscal year to redeem our preferred stock, $0.3 million of pre-redemption preferred dividend payments, and a $0.1 million decline in treasury stock purchases, partially offset by an increase of $2.2 million in common share dividends paid ~~reflecting three rate~~as a result of increases ~~made of the Board of Directors~~ in ~~fiscal 2017 and a $0.2 million decline in preferred share~~ dividend ~~payments and a $0.2 million decrease in treasury stock purchases.~~rates per share.

Full Cost Pool Ceiling Test and Proved Undeveloped Reserves

As of ~~September 30, 2017,~~March 31, 2018, 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 quarters of fiscal 2018. 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 full cost valuation “ceiling”): 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. 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, 2017 ~~consist of~~included 544 MBOE of reserves and $3.2 million of future development costs associated with a ~~proposed eight-well~~planned infill drilling program and 1,564 MBOE of reserves and $10.9 million of future development costs associated with the Phase V development in the eastern portion of the field. The objective of the infill drilling ~~programs objective~~program is to to increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The project ~~has aspects of~~includes both acceleration of production and an increase in ultimate ~~reserves~~reserve recovery and ~~is being treated~~has been recorded as a proved undeveloped project. The infill project, ~~is expected~~which was increased from eight wells to ~~begin~~twelve wells subsequent to the date of the reserve report, commenced drilling late in the third quarter of fiscal 2018. ~~Phase V~~The timing of our Test Site 5 development is ~~expected~~dependent in part on the results and CO₂ requirements of the infill program. The timing of such development is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within their portfolio of properties. At present, we expect to begin this development in ~~third quarter of fiscal~~calendar 2019.

Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~

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


	Three Months Ended September 30,										Three Months Ended March 31,
	2017		2016			Variance			Variance %		2018		2017		Variance			Variance %
Oil and gas production:
Crude oil revenues	$	7,829,255	$	7,593,855		$	235,400		3.1	%	$	9,639,238	$	9,060,796	$	578,442		6.4	%
NGL revenues	708,616		89			708,527			n.m.		610,328		464,641		145,687			31.4	%
Natural gas revenues	—		(4		)	4			n.m.
Total revenues	$	8,537,871	$	7,593,940		$	943,931		12.4	%	$	10,249,566	$	9,525,437	$	724,129		7.6	%

Crude oil volumes (Bbl)	166,737		178,002			(11,265		)	(6.3	)%	151,665		183,811		(32,146		)	(17.5	)%
NGL volumes (Bbl)	25,246		4			25,242			n.m.		17,926		19,594		(1,668		)	(8.5	)%
Natural gas volumes (Mcf)	—		16			(16		)	n.m.
Equivalent volumes (BOE)	191,983		178,009			13,974			7.9	%	169,591		203,405		(33,814		)	(16.6	)%

Crude oil (BOPD, net)	1,812		1,935			(123		)	(6.4	)%	1,685		2,042		(357		)	(17.5	)%
NGLs (BOEPD, net)	274		—			274			n.m.		199		218		(19		)	(8.7	)%
Equivalent volumes (BOEPD, net)	2,086		1,935			151			7.8	%	1,884		2,260		(376		)	(16.6	)%

Crude oil price per Bbl	$	46.96	$	42.66		$	4.30		10.1	%	$	63.56	$	49.29	$	14.27		29.0	%
NGL price per Bbl	28.07		22.25			5.82			26.2	%	34.05		23.71		10.34			43.6	%
Natural gas price per Mcf	—		(0.25		)	0.25			n.m.
Equivalent price per BOE	$	44.47	$	42.66		$	1.81		4.2	%	$	60.44	$	46.83	$	13.61		29.1	%

CO₂ costs	$	1,088,261	$	1,078,133		$	10,128		0.9	%	$	1,459,349	$	1,049,035	$	410,314		39.1	%
All other lease operating expenses	1,803,325		1,266,508			536,817			42.4	%	1,901,254		1,762,223		139,031			7.9	%
Production costs	$	2,891,586	$	2,344,641		$	546,945		23.3	%	$	3,360,603	$	2,811,258	$	549,345		19.5	%
Production costs per BOE	$	15.06	$	13.17		$	1.89		14.4	%	$	19.82	$	13.82	$	6.00		43.4	%

CO₂ volumes (MMcf per day, gross)	69.3		73.7			(4.4		)	(6.0	)%	75.7		66.3		9.4			14.2	%

Oil and gas DD&A (a)	$	1,510,881	$	1,265,637		$	245,244		19.4	%	$	1,353,340	$	1,515,368	$	(162,028	)	(10.7	)%
Oil and gas DD&A per BOE	$	7.87	$	7.11		$	0.76		10.7	%	$	7.98	$	7.45	$	0.53		7.1	%

~~n.m. Not meaningful.~~

(a) Excludes ~~$7,662~~$7,545 and ~~$7,802~~$8,107 of other depreciation and amortization expense for the three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively.

Net Income Available to Common Stockholders. ~~For~~During the three months ended ~~September 30, 2017,~~March 31, 2018, we generated net income of ~~$2.1~~$3.1 million, or ~~$0.06~~$0.09 per diluted share, on total revenues of ~~$8.5~~$10.2 million. This compares to a net income of ~~$0.6~~$2.4 million, or ~~$0.02~~$0.07 per diluted share, on revenues of ~~$7.6~~$9.5 million for the year-ago quarter. The ~~$1.6~~$0.6 million earnings increase reflects a ~~$0.9~~$0.7 million revenue increase, ~~$0.5~~a $0.9 million decline in income taxes primarily attributable to the impact of ~~lower income tax expense~~the 2017 Tax Cuts and ~~a $1.3 million decrease in allocated net income to holders of preferred shares retired in November 2016,~~Jobs Act, partially offset by ~~$1.1~~$1.0 million of higher operating expenses.

Oil and Gas Revenues. Revenues increased ~~12%~~8% to ~~$8.5~~$10.2 million ~~primarily~~ as a result of a 8%29% increase in ~~production volumes~~realized oil and NGL prices to $60.44 per equivalent barrel from $46.83 in the year-ago quarter, ~~together with~~partially offset by a ~~4% increase~~16.6% decrease in ~~realized prices from $42.66 per equivalent barrel~~production volumes. Current quarter NGL and oil production were adversely effected by abnormal sub-freezing temperatures that caused disruptions to ~~$44.47 per equivalent barrel~~our operations and resulted in ~~the current quarter. Delhi~~lost production of approximately seven days of crude oil and ~~natural gas liquids~~over twenty-five days of NGL production ~~comprised all~~in January 2018. Compared to the year-ago quarter, net oil production volumes decreased by 357 BOPD, or 17.5%, to 1,685 BOPD, and net NGL production decreased by 8.7% to199 BOEPD. All of our ~~current quarter revenues and virtually all~~ revenues for the current and year-ago quarter. Net Delhi oil production volumes of 1,812 BOPD decreased 123 BOPD from a year ago as a result of reduced production enhancement and conformance operations in the field. NGL net revenues averaged 274 BOEPD as sales of productionquarters came from the Delhi ~~NGL plant in the current quarter.~~field.

Production Costs. Production costs for the current quarter were ~~$2.9~~$3.4 million, a $0.5 million, or ~~23%~~20%, increase from ~~a year ago, primarily~~the year-ago quarter, due to ~~the expense of the NGL plant which started up December 31, 2016. Current cost includes $1.1 million for~~higher CO₂ costs of $0.4 million, or 39%, together with a ~~1% increase. A 6% decline~~$0.1 million, or 8%, increase in ~~purchase volumes reflecting operational efficiencies~~other production costs. The CO₂ cost increase was ~~almost offset by~~due to a higher purchase cost per ~~mcf,~~Mcf, which is ~~derived~~correlated with the 29% increase in realized oil price from ~~the realized field oil price.~~a year ago, and a 14% increase in purchased volumes. Average gross ~~purchase~~purchased CO₂ volumes ~~decreased~~increased from ~~73.7~~66.3 MMcf per day in the year-ago quarter to ~~69.3~~75.7 MMcf per day for the current quarter. ~~The current quarter's~~Other production costs, ~~were $15.06~~which include incremental costs of the NGL plant, power, chemicals, expensed workovers, maintenance, labor and overhead, increased primarily due to higher workover expense. Current quarter total production costs per equivalent barrel increased $6.00 per BOE ~~on total~~to $19.82 per BOE from $13.82 per BOE in the year-ago quarter due to the purchased CO₂ and other production ~~volumes.~~ cost increases together with the decrease in equivalent barrel production as described above. Approximately 30% of the rate increase was due to the temporary decline in oil production as a result of the cold weather event.

Calculated solely on our Delhi working interest volumes, production costs were ~~$19.77~~$26.46 per ~~barrel,~~BOE, of which ~~$7.81~~$11.85 per ~~barrel~~BOE was CO₂cost. These costs per equivalent 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 increased ~~$0.3~~$0.6 million, or ~~27%~~44%, to ~~$1.6~~$1.8 million for the three months ended ~~September 30, 2017 due to increases~~March 31, 2018. The increase resulted primarily from $0.4 million of ~~$0.2 million~~higher litigation costs and $0.1 million of due diligence costs associated with property evaluations.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased $0.2 million, or 11%, to $1.4 million compared to the year ago quarter primarily as a result of lower full cost amortization expense due to the 16.6% production decrease to 169,591 BOE, partially offset by a 7% increase in amortization rate to $7.98 per BOE. The higher rate was principally due to increased development costs.

Nine Months Ended March 31, 2018 and 2017

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



	Nine Months Ended March 31,
	2018		2017			Variance			Variance %
Oil and gas production:
Crude oil revenues	$	27,654,128	$	25,184,468		$	2,469,660		9.8	%
NGL revenues	2,200,220		464,730			1,735,490			373.4	%
Natural gas revenues	—		(4		)	4			n.m.
Total revenues	$	29,854,348	$	25,649,194		$	4,205,154		16.4	%

Crude oil volumes (Bbl)	496,169		544,628			(48,459		)	(8.9	)%
NGL volumes (Bbl)	69,205		19,598			49,607			253.1	%
Natural gas volumes (Mcf)	—		16			(16		)	n.m.
Equivalent volumes (BOE)	565,374		564,229			1,145			0.2	%

Crude oil (BOPD, net)	1,811		1,988			(177		)	(8.9	)%
NGLs (BOEPD, net)	252		71			181			254.9	%
Natural gas (BOEPD, net)	—		—			—			n.m.
Equivalent volumes (BOEPD, net)	2,063		2,059			4			0.2	%

Crude oil price per Bbl	$	55.74	$	46.24		$	9.50		20.5	%
NGL price per Bbl	31.79		23.71			8.08			34.1	%
Natural gas price per Mcf	—		(0.25		)	0.25			n.m.
Equivalent price per BOE	$	52.80	$	45.46		$	7.34		16.1	%

CO₂ costs	$	3,813,192	$	3,168,909		$	644,283		20.3	%
All other lease operating expenses	5,353,509		4,279,411			1,074,098			25.1	%
Production costs	$	9,166,701	$	7,448,320		$	1,718,381		23.1	%
Production costs per BOE	$	16.21	$	13.20		$	3.01		22.8	%

CO₂ volumes (MMcf per day, gross)	71.5		69.0			2.5			3.6	%

Oil and gas DD&A (a)	$	4,490,545	$	4,080,818		$	409,727		10.0	%
Oil and gas DD&A per BOE	$	7.94	$	7.23		$	0.71		9.8	%

n.m. Not meaningful.

(a) Excludes $22,751and $23,606 of other depreciation and amortization expense for the nine months ended March 31, 2018 and 2017, respectively.

Net Income Available to Common Stockholders. During the nine months ended March 31, 2018, we generated net income of $15.1 million, or $0.45 per diluted share, on total revenues of $29.9 million. This compares to net income of $5.3 million, or $0.16 per diluted share, on revenues of $25.6 million for the nine months ended March 31, 2017. The $9.8 million earnings increase reflects higher revenues of $4.2 million, an income tax decrease of $7.8 million primarily attributable to the impact of Tax Cuts and Jobs Act, and a $1.3 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $3.5 million of higher operating expenses.

Oil and Gas Revenues. Revenues increased 16% to $29.9 million during the nine months ended March 31, 2018 primarily due to a16% increase in realized prices from $45.46 per equivalent barrel to $52.80 per equivalent barrel on a very slight increase in equivalent barrels. All of our revenues in the current fiscal year came from the Delhi field, as did virtually all of our revenues from the prior year. Net Delhi oil production volumes of 1,811 BOPD at an average price of $55.74 decreased 177 BOPD from the prior year period primarily due to the abnormal sub-freezing temperatures that disrupted operations early in the current quarter together with successful conformance and production enhancement operations in the prior year that stabilized at lower rates in the current fiscal year. Net NGL production averaged 252 BOEPD, at an average price of $31.79 per barrel, an increase of 181 BOEPD compared to in the year-ago period as NGL plant production began in January 2017.

Production Costs. Production costs for the nine months ended March 31, 2018 were $9.2 million, a $1.7 million, or 23%, increase from the same period a year ago, primarily due to higher CO₂ costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO₂ costs increased $0.6 million, or 20%, due to higher purchased CO₂ costs per Mcf, which is correlated with the 21% increase in realized oil price from the prior year period together with a 4% increase in purchase volumes. Average gross purchased CO₂ volumes increased from 69.0 MMcf per day in the year-ago period to 71.5 MMcf per day for the current year. Other production costs, which include incremental costs of the NGL plant, power, chemicals, expensed workovers, repairs and maintenance, labor and overhead, increased $1.1 million, or 25%, from the year-ago period. Approximately $0.8 million and $0.3 million of this increase were due to higher NGL plant-related expense and workover expense, respectively. Total production costs per equivalent barrel in the current period were $16.21 per BOE on total production volumes, compared to $13.20 in the prior year period.

Calculated solely on our Delhi working interest volumes, production costs were $21.41 per BOE, of which $9.29 per BOE was CO₂cost. These costs per equivalent 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 increased $1.3 million, or 35%, to $5.1 million for the nine months ended March 31, 2018. The expense increase reflected $0.5 million of litigation and settlement expenses, $0.4 million of non-cash ~~stock~~stock-based compensation expense, and ~~severance expense, respectively. During the quarter, we reduced our employee count by one full time employee.~~$0.3 million of due diligence costs associated with property evaluations.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased ~~$0.2~~$0.4 million, or ~~19%~~10%, to ~~$1.5~~$4.5 million for the ~~current quarter~~nine months ended March 31, 2018 compared to the year-ago period primarily due to ~~higher~~increased full cost ~~pool depletion reflecting~~amortization from a ~~7.9% increase in production to 191,983 BOE, together with a 11%~~ higher amortization rate of ~~$7.87~~$7.94 per BOE compared to $7.23 per BOE in the year ago period and a small increase in production volumes 565,374 BOE. The higher rate iswas principally due to increased ~~future~~development costs.

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 impact our lease operating expenses and our capital expenditures. During fiscal 2018 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 ~~at June 30, 2017.~~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 exceeds 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. While we realized higher average oil prices in the current quarter than any period since the quarter ended December 31, 2014, there can be no assurance that such prices will continue to prevail or trend upward.

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 occasionally experience seasonality in the product prices we receive, driven by summer

cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes. We have also experienced adverse impacts on our production from very high summer temperatures and extremely cold winter weather.

Off Balance Sheet Arrangements

The Company ~~has~~had no off-balance sheet arrangements to report ~~during~~for the quarter ended ~~September 30, 2017.~~March 31, 2018.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended ~~September 30, 2017,~~March 31, 2018, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2017.

Commodity Price Risk

Our most significant market risk is the pricing for crude oil ~~natural gas~~ and ~~NGLs.~~NGL's. 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 ~~September 30, 2017~~March 31, 2018 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 ~~September 30, 2017~~March 31, 2018, we have determined there has been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in our Annual Report on Form 10-K for the year ended June 30, ~~20017~~2017 in Part I. Item 3. “Legal Proceedings” and Note 18 — Commitments and Contingencies under Part II. Item 8. “Financial Statements.” Material developments in the status of those proceedings during the quarter ended ~~September 30, 2017~~March 31, 2018 are described in Part I. Item 1. "Financial Information" under Note 1514 — 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, 2017 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, 2017.

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

During the quarter ended ~~September 30, 2017,~~March 31, 2018, 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 September 30, 2017, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and contingent restricted stock. During this quarter,March 31, 2018, the Company did not purchase any common stock in the open market under the previously announced share repurchase ~~program. The table below summarizes information about the Company's purchases of its equity securities during the quarter ended September 30, 2017.~~

Period
(a) Total Number of
Shares
Purchased (1)

(b) Average Price
Paid per Share(1)

(c) Total Number of Shares Purchased as Part
of Publicly Announced Plans or Programs (2)

(d) Maximum
Dollar Value
of Shares that
May Yet Be Purchased
Under the Plans or
Programs (2)
July 2017 None Not applicable Not applicable $3.4 million
August 2017 6,564 $7.64 Not applicable $3.4 million
September 2017 8,720 $6.95 Not applicable $3.4 million
Total 15,284 $7.25 Not applicable $3.4 million

~~(1)During the current quarter the Company received~~program and no shares of common stock ~~from certain of~~were surrendered by its employees ~~which were surrendered in exchange for~~to pay their share of payroll ~~tax liabilities~~taxes arising from vestings of restricted stock ~~and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price~~and/or exercises of ~~the Company's shares on the dates vested.~~

~~(2)~~On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock ~~then subsequently canceled.~~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

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: ~~November 8, 2017~~May 9, 2018

2427



Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share(1)	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)
July 2017	None	Not applicable	Not applicable	$3.4 million
August 2017	6,564	$7.64	Not applicable	$3.4 million
September 2017	8,720	$6.95	Not applicable	$3.4 million
Total	15,284	$7.25	Not applicable	$3.4 million

Outstanding Potentially Dilutive Securities

Weighted
Average
Exercise Price

At ~~September 30, 2017~~March 31, 2018

Contingent Restricted Stock grants

~~94,244~~61,868