UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, ~~2018~~2019

oTRANSITION 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 filero	o		Accelerated filer	x
	Non-accelerated filer	o ~~(Do not check if a smaller reporting company)~~
	Smaller reporting company o	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

APPLICABLE ONLY TO CORPORATE ISSUERS:

~~The~~Indicate the number of shares outstanding of each of the ~~registrant’s~~issuer’s classes of common stock, as of the latest practicable date.

33,186,665 shares outstanding of common stock, par value $0.001, as of May ~~4, 2018, was 33,171,514.~~6, 2019.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS



Forward-Looking Statements			~~Page~~
		ii
~~PART~~Part I. ~~FINANCIAL INFORMATION~~Financial Information		21
Item 1.
~~ITEM 1.~~Financial Statements	~~UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS~~1	2

	Unaudited Consolidated Condensed Balance Sheets as of March 31, ~~2018~~2019 and June 30, ~~2017~~2018	21
	Unaudited Consolidated Condensed Statements of Operations for the three and nine months ended March 31, ~~2018~~2019 and ~~2017~~2018	32
	Unaudited Consolidated Condensed Statements of Cash Flows for the nine months ended March 31, ~~2018~~2019 and ~~2017~~2018	43
	Unaudited Consolidated Condensed ~~Statement~~Statements of Stockholders’ Equity for the three and nine months ended March 31, 2019 and 2018	54
	Notes to Unaudited Consolidated Condensed Financial Statements	65
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
Item 4.	Controls and Procedures	22
~~ITEM 2.~~Part II. Other Information		~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~23
Item 1.	Legal Proceedings	1623
Item 1A.	Risk Factors	23
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23
Item 3.	Defaults Upon Senior Securities	23
Item 4.	Mine Safety Disclosures	23
Item 5.	Other Information	23
Item 6.	Exhibits	23
~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~	25

~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~	25

~~PART II. OTHER INFORMATION~~		26

~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~	26

~~ITEM 1A.~~	~~RISK FACTORS~~	26

~~ITEM 2.~~	~~UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS~~	26

~~ITEM 3.~~	~~DEFAULTS UPON SENIOR SECURITIES~~	26

~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~	26

~~ITEM 5.~~	~~OTHER INFORMATION~~	26

~~ITEM 6.~~	~~EXHIBITS~~	26

~~SIGNATURES~~Signatures		2724

Table of Contents

FORWARD-LOOKING STATEMENTS

This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part II, Item 1A, "Risk Factors" and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in conjunction with our consolidated condensed financial statements and related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. You are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.

Table of Contents

PART I — FINANCIAL INFORMATION

~~ITEM~~Item 1. ~~CONSOLIDATED~~Consolidated Condensed ~~CONDENSED~~Financial Statements~~FINANCIAL STATEMENTS~~

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)


	March 31, 2018		June 30, 2017		March 31, 2019		June 30, 2018
Assets
Current assets
Cash and cash equivalents	$	27,186,809	$	23,028,153	$	29,550,385	$	24,929,844
Restricted cash					—		2,751,289
Receivables	3,949,973		2,726,702		3,687,016		3,941,916
Prepaid expenses and other current assets	682,645		387,672		679,871		524,507
Total current assets	31,819,427		26,142,527		33,917,272		32,147,556
Oil and natural gas property and equipment, net (full-cost method of accounting)	59,589,750		61,790,068
Oil and natural gas properties, net (full-cost method of accounting)					61,333,933		61,239,746
Other property and equipment, net	34,144		40,689		20,120		30,407
Total property and equipment	59,623,894		61,830,757		61,354,053		61,270,153
Other assets	243,011		295,384		220,190		244,835
Total assets	$	91,686,332	$	88,268,668	$	95,491,515	$	93,662,544
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	2,786,518	$	1,994,255	$	2,123,776	$	3,432,568
Accrued liabilities and other	628,663		724,639		571,009		874,886
State and federal income taxes payable					99,918		122,760
Total current liabilities	3,415,181		2,718,894		2,794,703		4,430,214
Long term liabilities
Senior secured credit facility (Note 13)	—		—		—		—
Deferred income taxes	10,754,077		15,826,291		11,189,060		10,555,435
Asset retirement obligations	1,319,291		1,253,628		1,533,083		1,387,416
Total liabilities	15,488,549		19,798,813		15,516,846		16,373,065
Commitments and contingencies (Note 14)
Stockholders’ equity
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
Common stock; par value $0.001; 100,000,000 shares authorized; 33,186,665 and 33,080,543 shares issued and outstanding as of March 31, 2019 and June 30, 2018, respectively					33,186		33,080
Additional paid-in capital	41,890,553		40,961,957		42,297,050		41,757,645
Retained earnings	34,274,059		27,474,811		37,644,433		35,498,754
Total stockholders’ equity	76,197,783		68,469,855		79,974,669		77,289,479
Total liabilities and stockholders’ equity	$	91,686,332	$	88,268,668	$	95,491,515	$	93,662,544

See accompanying notes to consolidated condensed financial statements.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)


	Three Months Ended March 31,						Nine Months Ended March 31,						Three Months Ended March 31,						Nine Months Ended March 31,
	2018			2017			2018			2017			2019			2018			2019			2018
Revenues
Crude oil	$	9,639,238		$	9,060,796		$	27,654,128		$	25,184,468		$	9,032,032		$	9,639,238		$	30,945,359		$	27,654,128
Natural gas liquids	610,328			464,641			2,200,220			464,730			468,525			511,917			1,910,395			1,825,214
Natural gas	—			—			—			(4		)	471			—			471			—
Total revenues	10,249,566			9,525,437			29,854,348			25,649,194			9,501,028			10,151,155			32,856,225			29,479,342
Operating costs
Production costs	3,360,603			2,811,258			9,166,701			7,448,320			3,793,008			3,262,192			10,703,606			8,791,695
Depreciation, depletion and amortization	1,360,885			1,523,475			4,513,296			4,104,424			1,558,130			1,383,148			4,710,223			4,580,161
Accretion of discount on asset retirement obligations	22,263			13,562			66,865			39,892
General and administrative expenses *	1,842,548			1,283,906			5,078,508			3,760,348			1,196,935			1,842,548			3,760,767			5,078,508
Total operating costs	6,586,299			5,632,201			18,825,370			15,352,984			6,548,073			6,487,888			19,174,596			18,450,364
Income from operations	3,663,267			3,893,236			11,028,978			10,296,210			2,952,955			3,663,267			13,681,629			11,028,978
Other
Gain on realized derivative instruments, net	—			3,350			—			3,440
Gain on unrealized derivative instruments, net	—			47,965			—			33,833
Enduro transaction breakup fee													—			—			1,100,000			—
Interest and other income	21,345			13,099			52,036			39,905			65,831			21,345			172,260			52,036
Interest expense	(30,525		)	(20,317		)	(71,436		)	(61,373		)	(28,789		)	(30,525		)	(87,479		)	(71,436		)
Income before income taxes	3,654,087			3,937,333			11,009,578			10,312,015			2,989,997			3,654,087			14,866,410			11,009,578
Income tax provision (benefit)	585,733			1,518,190			(4,076,156		)	3,768,463			591,122			585,733			2,767,169			(4,076,156		)
Net income attributable to the Company	3,068,354			2,419,143			15,085,734			6,543,552
Dividends on preferred stock	—			—			—			250,990
Deemed dividend on redeemed preferred shares	—			—			—			1,002,440
Net income available to common stockholders	$	3,068,354		$	2,419,143		$	15,085,734		$	5,290,122		$	2,398,875		$	3,068,354		$	12,099,241		$	15,085,734
Earnings per common share
Basic	$	0.09		$	0.07		$	0.46		$	0.16		$	0.07		$	0.09		$	0.36		$	0.46
Diluted	$	0.09		$	0.07		$	0.45		$	0.16		$	0.07		$	0.09		$	0.36		$	0.45
Weighted average number of common shares
Basic	33,171,514			33,062,297			33,123,185			33,021,865			33,186,665			33,171,514			33,151,786			33,123,185
Diluted	33,191,312			33,115,699			33,155,870			33,064,708			33,196,197			33,191,312			33,163,661			33,155,870

* General and administrative expenses for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 included non-cash stock-based compensation ~~expense~~expenses of ~~$352,420~~$208,665 and ~~$291,151,~~$352,420, respectively. For the ~~corresponding~~ nine ~~month periods,~~months ended March 31, 2019 and 2018, non-cash stock-based compensation ~~expense was~~expenses were $678,149 and $1,324,230, ~~and $878,023,~~ respectively.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)


	Nine Months Ended March 31,						Nine Months Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities
Net income attributable to the Company	$	15,085,734		$	6,543,552		$	12,099,241		$	15,085,734
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	4,555,496			4,146,898			4,721,590			4,622,361
Stock-based compensation	1,324,230			878,023			678,149			1,324,230
Accretion of discount on asset retirement obligations	66,865			39,892
Settlements of asset retirement obligations	—			(157,910		)
Deferred income taxes (benefit)	(5,072,214		)	3,079,342
Gain on derivative instruments, net	—			(37,273		)
Deferred income tax expense (benefit)							633,625			(5,072,214		)
Changes in operating assets and liabilities:
Receivables	(1,223,271		)	(723,161		)	254,900			(1,223,271		)
Prepaid expenses and other current assets	(294,973		)	(445,597		)	(155,364		)	(294,973		)
Accounts payable and accrued expenses	73,678			(1,808,566		)
Accounts payable and accrued liabilities							123,853			73,678
Income taxes payable	—			(164,544		)	(22,842		)	—
Net cash provided by operating activities	14,515,545			11,350,656			18,333,152			14,515,545
Cash flows from investing activities
Derivative settlement payments paid	—			(318,618		)
Capital expenditures for oil and natural gas properties	(1,668,820		)	(10,096,475		)	(6,369,363		)	(1,668,820		)
Capital expenditures for other property and equipment	(6,033		)	(32,260		)	(2,337		)	(6,033		)
Net cash used in investing activities	(1,674,853		)	(10,447,353		)	(6,371,700		)	(1,674,853		)
Cash flows from financing activities
Cash dividends to preferred stockholders	—			(250,990		)
Cash dividends to common stockholders	(8,286,486		)	(6,116,323		)	(9,953,562		)	(8,286,486		)
Common share repurchases, including shares surrendered for tax withholding	(395,550		)	(459,858		)	(138,638		)	(395,550		)
Redemption of preferred shares	—			(7,932,975		)
Other	—			32
Net cash used in financing activities	(8,682,036		)	(14,760,114		)	(10,092,200		)	(8,682,036		)
Net increase (decrease) in cash and cash equivalents	4,158,656			(13,856,811		)
Cash and cash equivalents, beginning of period	23,028,153			34,077,060
Cash and cash equivalents, end of period	$	27,186,809		$	20,220,249
Net increase in cash, cash equivalents and restricted cash							1,869,252			4,158,656
Cash, cash equivalents and restricted cash, beginning of period							27,681,133			23,028,153
Cash, cash equivalents and restricted cash, end of period							$	29,550,385		$	27,186,809


Supplemental disclosures of cash flow information:	Nine Months Ended March 31,						Nine Months Ended March 31,
	2018			2017			2019			2018
Income taxes paid	$	1,456,754		$	1,383,773		$	2,362,919		$	1,456,754
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	622,185			(3,181,640		)
Change in accounts payable used to acquire oil and natural gas properties							(1,748,122		)	622,185
Oil and natural gas property costs incurred through recognition of asset retirement obligations	(778		)	14,119			84,999			(778		)

See accompanying notes to consolidated condensed financial statements.

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed ~~Statement~~Statements of Changes in Stockholders' Equity

~~For the Nine Months Ended March 31, 2018~~

(Unaudited)


	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
For the Three Months Ended March 31, 2019:						Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance at December 31, 2018																		33,186,665		$	33,186		$	42,088,385		$	38,564,224		$	—		$	80,685,795
Stock-based compensation																		—		—			208,665			—			—			208,665
Net income attributable to the Company																		—		—			—			2,398,875			—			2,398,875
Common stock cash dividends, $0.10 per share																		—		—			—			(3,318,666		)	—			(3,318,666		)
Balance at March 31, 2019																		33,186,665		$	33,186		$	42,297,050		$	37,644,433		$	—		$	79,974,669
	Shares		Par Value			Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
For the Nine Months Ended March 31, 2019:						Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance at June 30, 2018																		33,080,543		$	33,080		$	41,757,645		$	35,498,754		$	—		$	77,289,479
Issuance of restricted common stock																		121,611		122			(122		)	—			—			—
Common share repurchases, including shares surrendered for tax withholding																		(15,489	)	—			—			—			(138,638		)	(138,638		)
Retirements of treasury stock																		—		(16		)	(138,622		)	—			138,638			—
Stock-based compensation																		—		—			678,149			—			—			678,149
Net income attributable to the Company																		—		—			—			12,099,241			—			12,099,241
Common stock cash dividends, $0.10 per share																		—		—			—			(9,953,562		)	—			(9,953,562		)
Balance at March 31, 2019																		33,186,665		$	33,186		$	42,297,050		$	37,644,433		$	—		$	79,974,669

For the Three Months Ended March 31, 2018:
Balance at December 31, 2017																		33,171,514		$	33,171		$	41,538,133		$	34,522,856		$	—		$	76,094,160
Stock-based compensation																		—		—			352,420			—			—			352,420
Net income attributable to the Company																		—		—			—			3,068,354			—			3,068,354
Common stock cash dividends, $0.10 per share																		—		—			—			(3,317,151		)	—			(3,317,151		)
Balance at March 31, 2018																		33,171,514		$	33,171		$	41,890,553		$	34,274,059		$	—		$	76,197,783

For the Nine Months Ended March 31, 2018:
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	158,785		158			(158		)	—			—			—			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	(55,018	)	—			—			—			(395,550		)	(395,550		)	(55,018	)	—			—			—			(395,550		)	(395,550		)
Retirements of treasury stock	—		(54		)	(395,496		)	—			395,550			—			—		(54		)	(395,496		)	—			395,550			—
Stock-based compensation	—		—			1,324,230			—			—			1,324,230			—		—			1,324,230			—			—			1,324,230
Net income attributable to the Company	—		—			—			15,085,734			—			15,085,734			—		—			—			15,085,734			—			15,085,734
Common stock cash dividends	—		—			—			(8,286,486		)	—			(8,286,486		)
Common stock cash dividends, $0.083 per share																		—		—			—			(8,286,486		)	—			(8,286,486		)
Balance at March 31, 2018	33,171,514		$	33,171		$	41,890,553		$	34,274,059		$	—		$	76,197,783		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"~~"Company," "EPM," "Evolution," "we," "our," or "us"), is an ~~independent petroleum~~oil and gas company ~~headquartered in Houston, Texas~~focused on delivering a sustainable dividend yield to its stockholders through the ownership, management and ~~incorporated under the laws of the State of Nevada. We are engaged primarily in the~~ development ~~and production~~ of oil and gas ~~reserves.~~properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties. Our largest active investment is our interest in a CO₂ enhanced oil recovery project in Louisiana's Delhi field.

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 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~~GAAP 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~~2018 Annual Report on Form 10-K for the fiscal year ended June 30, ~~2017,~~2018, 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.~~subsidiaries (the "Company"). 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 may 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~~Note 2 — Summary of Significant Accounting ~~Pronouncements.~~Policies

Revenue Recognition

~~In August 2015,~~Effective July 1, 2018, the ~~Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-14, which defers the effective date of~~Company adopted ASU No. 2014-09, Revenue ~~from~~From Contracts ~~with~~With Customers (Topic 606) (" ~~ASU 2014-09"~~(“ASC 606”) ~~by one year~~using the full retrospective method and ~~allows entities~~has applied the ~~option~~standard to early adopt the new revenue standard as of the original effective date, which for public business entities was for fiscal years beginning after December 31, 2016. Issued in May 2014, ASU 2014-09 provided guidance onall existing contracts. ASC 606 supersedes previous revenue recognition ~~for contracts with customers to transfer goods or services or for contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that~~requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition ~~for contracts with customers~~model to 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 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 asAs a result of adopting ~~ASU 2014-09~~ASC 606, the Company did not have a cumulative-effect adjustment in retained earnings. The comparative information presented therein for the three and ~~is currently assessing~~nine months ended March 31, 2018 reflects the reclassification on our consolidated statement of operations of $98,411 and $375,006, respectively, from “Production Costs” to “Revenue - Natural Gas Liquids” in conformance with ASC 606. These changes to revenue and production costs resulted from the conclusion that the Company did not control the product throughout processing before transferring to the customer. Therefore, costs incurred after the transfer of control are treated as reductions of revenue. Additionally, adoption of ASC 606 did not impact net income attributable to common stockholders, current assets, total assets, current liabilities, total liabilities or stockholders’ equity and the Company does not expect that it will do so in future periods.

Our revenues are comprised solely of revenues from customers from the ~~guidance~~sale of crude oil, NGLs and natural gas. The Company believes that the disaggregation of revenue on its consolidated ~~financial statements.~~statements of operations into these three major product types appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on our single geographic location. Crude oil and NGL revenues are recognized at a point in time when production is sold to a purchaser at an index-based, determinable price, delivery has occurred, control has transferred and collectibility of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms which

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Notes to Unaudited Consolidated Condensed Financial Statements

reference index price sources used by the industry. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days for crude oil and 60 days for NGLs after the end of the production month. At the end of each month when the performance obligations have been satisfied, the consideration can be reasonably estimated and amounts due from customers are accrued in “Receivables” in our consolidated balance sheets. As of March 31, 2019 and June 30, 2018, receivables from contracts with customers were $3.7 million and $3.9 million, respectively.

Other Recently Adopted Accounting Pronouncements

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)~~investees) 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~~

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~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~December 15, 2017. The expected adoption method of~~Effective July 1, 2018, the Company prospectively adopted ASU 2016-01 ~~is being evaluated by the Company and the adoption is not expected~~without impact to ~~have a significant impact on the Company’s~~its consolidated financial position or results of operations. Because its investment in Well Lift Inc. does not have a readily determinable fair value, the Company elected to measure this investment at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if they were to occur.

Effective July 1, 2018, the Company retrospectively adopted ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, 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. Adoption had no effect on our current period and comparative consolidated statements of cash flows.

Effective July 1, 2018, the Company prospectively adopted ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will apply the clarified definition of business to future acquistions and divestitures.

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases (“(Topic 842) (“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~~statements 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 doeswe do not expect the ~~impact of adopting ASU 2016-15~~standard to have a material ~~effect on its consolidated statements of cash flows.~~impact.

Note 23 — Receivables

As of March 31, ~~2018~~2019 and June 30, ~~2017,~~2018, our receivables consisted of the following:

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

~~Note 3 — Prepaid Expenses and Other Current Assets~~

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

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



	March 31, 2019		June 30, 2018
Receivables from oil and NGL sales	$	3,686,969	$	3,940,998
Other	47		918
Total receivables	$	3,687,016	$	3,941,916

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Note 4 — Prepaid Expenses and Other Current Assets

As of March 31, 2019 and June 30, 2018, our prepaid expenses and other current assets consisted of the following:



	March 31, 2019		June 30, 2018
Prepaid insurance	$	31,572	$	198,558
Retainers and deposits	6,089		11,089
Prepaid federal and state income taxes	438,453		231,920
Prepaid consulting and other	203,757		82,940
Prepaid expenses and other current assets	$	679,871	$	524,507

Note 45 — Property and Equipment

As of March 31, ~~2018~~2019 and June 30, ~~2017,~~2018, our oil and natural gas properties and other property and equipment consisted of the following:


	March 31, 2018			June 30, 2017			March 31, 2019			June 30, 2018
Oil and natural gas properties
Property costs subject to amortization	$	87,253,160		$	84,962,933		$	95,099,158		$	90,392,918
Less: Accumulated depreciation, depletion, and amortization	(27,663,410		)	(23,172,865		)	(33,765,225		)	(29,153,172		)
Unproved properties not subject to amortization	—			—			—			—
Oil and natural gas properties, net	$	59,589,750		$	61,790,068		$	61,333,933		$	61,239,746
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	$	141,410		$	135,377		$	145,560		$	143,223
Less: Accumulated depreciation	(107,266		)	(94,688		)	(125,440		)	(112,816		)
Other property and equipment, net	$	34,144		$	40,689		$	20,120		$	30,407

During the nine months ended March 31, ~~2018~~2019 and ~~2017,~~2018, the Company incurred capital expenditures of ~~$2.3~~$4.7 million and ~~$6.9~~$2.3 million, respectively, in the Delhi field.

Note 56 — Other Assets

As of March 31, ~~2018~~2019 and June 30, ~~2017,~~2018, other assets consisted of the following:


	March 31, 2018			June 30, 2017			March 31, 2019			June 30, 2018
Royalty rights	$	108,512		$	108,512		$	108,512		$	108,512
Less: Accumulated amortization of royalty rights	(30,519		)	(20,346		)	(44,083		)	(33,910		)
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	(112,704		)	(70,504		)	(138,138		)	(126,771		)
Software license							20,662			20,662
Less: Accumulated amortization of software license							(4,485		)	(1,380		)
Other assets, net	$	243,011		$	295,384		$	220,190		$	244,835

Our royalty rights and investment in Well Lift, Inc. ("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 with the technology. We own 17.5% of the common stock of WLI and account for our investment ~~under~~in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the ~~cost method. Any dividends paid are recorded as income and any return~~identical or a similar investment of ~~capital reduces our cost basis in~~ the ~~investment. Our~~same issuer, if such were to occur. The Company evaluates the investment ~~in WLI is evaluated~~ for impairment ~~at least quarterly or~~ when ~~management~~it 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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Note 67 — Accrued Liabilities and Other

As of March 31, ~~2018~~2019 and June 30, ~~2017,~~2018, our other current liabilities consisted of the following:


	March 31, 2018		June 30, 2017		March 31, 2019		June 30, 2018
Accrued incentive and other compensation	$	412,439	$	413,113	$	322,538	$	415,182
Accrued severance payments					—		160,089
Asset retirement obligations due within one year	35,539		35,115		50,244		35,539
Accrued royalties, including suspended accounts	11,499		17,708		11,552		11,498
Accrued franchise taxes	124,299		150,062		136,425		162,805
Accrued ad valorem taxes	44,887		108,641		50,250		89,773
Accrued liabilities and other	$	628,663	$	724,639	$	571,009	$	874,886

Note 78 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we 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 nine months ended March 31, ~~2018~~2019 and for the year ended June 30, ~~2017:~~2018:



	March 31, 2019			June 30, 2018
Asset retirement obligations — beginning of period	$	1,422,955		$	1,288,743
Liabilities incurred	31,268			44,700
Accretion of discount	75,373			90,290
Revision of previous estimates	53,731			(778		)
Asset retirement obligations — end of period	$	1,583,327		$	1,422,955
Less current portion in accrued liabilities	(50,244		)	(35,539		)
Long-term portion of asset retirement obligations	$	1,533,083		$	1,387,416

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

Note 89 — Stockholders’ Equity

Common Stock

As of March 31, ~~2018,~~2019, we had ~~33,171,514~~33,186,665 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. We paid dividends of ~~$8,286,486~~$9,953,562 and ~~$6,116,323~~$8,286,486 to our common ~~shareholders~~stockholders during the nine months ended March 31, ~~2018~~2019 and ~~2017,~~2018, respectively. The following table reflects the dividends paid ~~in each quarter~~ within the respective ~~nine~~three month periods:


	Fiscal Year				Fiscal Year
	2018		2017		2019		2018
First quarter ended September 30,					$	0.10	$	0.075
Second quarter ended December 31,					$	0.10	$	0.075
Third quarter ended March 31,	$	0.100	$	0.070	$	0.10	$	0.100
Second quarter ended December 31,	$	0.075	$	0.065
First quarter ended September 30,	$	0.075	$	0.050

In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. 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 December 2015. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and

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~~Notes to Unaudited Consolidated Condensed Financial Statements~~

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.

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During the nine months ended March 31, ~~2018~~2019 and ~~2017,~~2018, the Company acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The treasury shares were subsequently canceled. Such shares were valued at fair market value on the date of vesting, as reflected in the following table:


	Nine Months Ended March 31,				Nine Months Ended March 31,
	2018		2017		2019		2018
Number of treasury shares acquired	55,018		73,455		15,489		55,018
Average cost per share	$	7.19	$	6.26	$	8.95	$	7.19
Total cost of treasury shares acquired	$	395,550	$	459,858	$	138,638	$	395,550

~~Series A Cumulative Preferred Stock Called for Redemption~~

In September 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 in November 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 nine months ended March 31, 2016, we paid cash dividends of $250,990 to holders of our Series A Preferred Stock prior to the November 2016 redemption date.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, ~~2017,~~2018, all ~~preferred and~~ common stock 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,~~2019, 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 March 31, ~~2018~~2019 and are subject to change based on our final tax calculations at the end of the fiscal year.

Note 910 — 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"). for which there were no shares available for future grants. The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of March 31, ~~2018, 987,845~~2019, 852,111 shares remained available for grant under the 2016 Plan.

~~At 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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~~Notes to Unaudited Consolidated Condensed Financial Statements~~

Restricted Stock and Contingent Restricted Stock

The Company ~~awards~~has awarded 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 are issued on the date of 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 they were granted under.

Service-based awards vest with continuous employment by the Company, generally in annual installments over ~~a four-year period.~~their terms of three to four years. 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 grant and amortized over the service period. During the nine months ended March 31, ~~2018,~~2019, we granted ~~112,155~~31,777 service-based and 43,990 market-based Restricted Stock awards ~~including 45,211~~to our employees as well as 35,215 service-based awards to ~~employees and 66,944 awards to directors, substantially all of which have a one-year vesting period.~~the Company's directors. We did not grant any performance-based ~~or market based~~ awards, nor any Contingent Restricted Stock awards, during this period. The employees' service-based awards vest annually over a three-year period and the directors' service-based awards have a one-year cliff vesting 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

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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.~~term of the award. As of March 31, ~~2018, certain contingent~~2019, there were no 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 would be recorded at that time and amortization would continue over the remaining expected vesting period.outstanding.

Market-based awards vest if ~~the~~their respective two- or three-year trailing total ~~return~~returns on the Company’s common stock ~~exceeds~~exceed the corresponding total returns of various quartiles of indices consisting of either peer companies or a broad market index of companies in our industry. More recent market-based awards vest if the average of the Company's closing stock prices over defined quarterly measurement periods together with accumulated paid dividends exceeds a defined value. The fair values and expected vesting periods of these awards 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. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the 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.

For market-based awards granted during the nine months ended March 31, 2019, the range of assumptions used in the Monte Carlo simulation valuations, expected lives and fair values were as follows:



	Nine Months Ended March 31,
	2019
Risk-free interest rate	2.69	%
Expected life in years	2.82
Expected volatility	41.8	%
Dividend yield	4.0	%

Unvested Restricted Stock awards at March 31, ~~2018~~2019 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	218,615	$	6.64	121,265	$	8.62
Performance-based awards	50,360	5.67
Market-based awards	50,359	5.44		64,302	7.35
Unvested Restricted Stock at March 31, 2018	319,334	$	6.30
Unvested Restricted Stock at March 31, 2019				185,567	$	8.18

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, ~~2018:~~2019:

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



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at March 31, 2019		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2018	199,477		$	6.83
Service-based shares granted	66,992		9.17
Market-based shares granted	43,990		8.24
Vested	(124,892	)	6.57
Unvested Restricted Stock at March 31, 2019	185,567		$	8.18	$	1,055,246	1.86

Unvested Contingent Restricted Stock awards at March 31, 2019 consisted of the following:

1110

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

Number of
Contingent
Restricted
Shares Weighted
Average
Grant-Date
Fair Value
Performance-based awards 36,688
$ 7.04
Market-based awards 25,180
3.42
Unvested contingent shares at March 31, 2018 61,868
$ 5.57

The following table sets forth Contingent Restricted Stock transactions for the nine months ended March 31, ~~2018:~~2019:

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

Vested (46,630 ) 3.34

Forfeited (4,772 ) 5.30

Unvested contingent shares at March 31, 2018 61,868
$ 5.57
$ 57,231
.91

~~(1) Excludes $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.~~



	Number of Contingent Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at March 31, 2019		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2018	28,562		$	6.06
Vested	(10,629	)	5.67
Expired	(7,777	)	10.05
Unvested contingent shares at March 31, 2019	10,156		$	3.42	$	3,029	.25

Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants for the three months ended March 31, 2019 and 2018 was $208,665 and ~~2017 was~~ $352,420, ~~and $291,151,~~ respectively. For the corresponding nine month periods, ~~non-cash stock~~stock-based compensation expense was $678,149 and $1,324,230, ~~and $878,023,~~ respectively.

~~Note 10~~—~~Derivatives~~

~~As of June 30, 2017 and March 31, 2018, the Company 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 of its near-term forecasted production. The Company's objectives are to achieve a more predictable level of cash flows to support the Company’s capital expenditure programs and to provide better financial visibility for its other financial commitments. The Company 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 Hedgin~~g ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in other non-operating income and expense. Given the cost and complexity, the Company has elected not to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, 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 recognized in earnings 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 amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

For the nine months ended March 31, 2018, the Company had no gains or losses from derivatives. For the nine months ended March 31, 2017, the Company recorded a gain on derivative instruments of $37,273 consisting of a realized gain of $3,440 on settled positions and an unrealized gain of $33,833.

Note 11 — 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 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~~2015 through June 30, ~~2017~~2018 for federal tax purposes and for the years ended June 30, ~~2013~~2014 through June 30, ~~2017~~2018 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.

For the nine months ended March 31, 2019 and 2018, respectively, we recognized income tax expense of $2.8 million and an income tax benefit of $(4.1) million. This benefit included a one-time $6.0 million tax credit, resulting from adjustment of our deferred income tax liabilities at December 31, 2017 in connection with enactment of the Tax Cut and Jobs Act (the "Tax Act"). For the nine months ended March 31, 2019 and 2018, the corresponding effective tax rates were 19% and (37)%. 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. For the nine months ended March 31, 2019 and 2018, our respective statutory federal tax rates were 21% and 27.55%, as we used a blended rate during the prior fiscal year in which the Tax Act was enacted. The benefit of this statutory rate reduction was partially offset by a decreased benefit from depletion in excess of basis as much of our depletion carryover had been utilized in fiscal 2018.

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Notes to Unaudited Consolidated Condensed Financial Statements

Note 12 — Net Income Per Share

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


	Three Months Ended March 31,				Nine Months Ended March 31,				Three Months Ended March 31,				Nine Months Ended March 31,
	2018		2017		2018		2017		2019		2018		2019		2018
Numerator
Net income available to common shareholders	$	3,068,354	$	2,419,143	$	15,085,734	$	5,290,122	$	2,398,875	$	3,068,354	$	12,099,241	$	15,085,734
Denominator
Weighted average number of common shares — Basic	33,171,514		33,062,297		33,123,185		33,021,865		33,186,665		33,171,514		33,151,786		33,123,185
Effect of dilutive securities:
Contingent restricted stock grants	19,798		27,216		32,685		17,860		9,532		19,798		11,875		32,685
Stock options	—		26,186		—		24,983
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		33,196,197		33,191,312		33,163,661		33,155,870

Net income per common share — Basic	$	0.09	$	0.07	$	0.46	$	0.16	$	0.07	$	0.09	$	0.36	$	0.46
Net income per common share — Diluted	$	0.09	$	0.07	$	0.45	$	0.16	$	0.07	$	0.09	$	0.36	$	0.45

Outstanding potentially dilutive securities as of March 31, ~~2018~~2019 were as follows:

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


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		At March 31, 2017	Weighted Average Exercise Price		At March 31, 2018
Contingent Restricted Stock grants	$	—	113,270	$	—	$	61,868
Stock Options	2.19		35,231
Total outstanding potentially dilutive securities	$	0.52	148,501

Note 13 — 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~~On May 25, 2018, we entered into the ~~Company's previous unsecured~~third amendment to our credit agreement governing the revolving credit facility ~~which expired in~~to, among other things, extend the maturity date to April ~~2016. The borrowing base under~~11, 2021. On December 31, 2018, we entered into the ~~Facility was originally set at $10 million and was subsequently increased~~fourth amendment to ~~$40 million effective February 1, 2018.~~ our credit agreement governing the revolving credit facility to broaden the definition for the Use of Proceeds.

As of March 31, ~~2018,~~2019, the ~~Company was~~Company's elected commitment and borrowing base were $40 million, we were in compliance with all financial covenants ~~contained in the Facility,~~ and there were no amounts ~~were~~ outstanding under the Facility, which is secured by substantially all of the Company’s assets.

Under the Facility the borrowing base shall be determined semiannually as of every May 15 and November 15 during the term of the Facility. During the current quarter, the bank performed its periodic spring redetermination of the borrowing base and confirmed our elected amount of $40 million.

Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, 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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Notes to Unaudited Consolidated Condensed Financial Statements

1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $50 million, all as defined under the Facility.

In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was ~~$56,268~~$30,834 as of March 31, ~~2018.~~2019.

Note 14 — 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. We vigorously defended the claims. Based on our assessment of the continuing costs of defending the Company in this 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 ofLease Commitment. At March 31, ~~2018 and paid by the Company in April, is not material to the financial position of the Company.~~

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

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



Twelve month periods ended March 31,
2020	$	12,179

Rent expense for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 was $18,568 and ~~$14,656,~~$18,568, respectively. ~~Rent expense for~~For the nine months ended March 31, 2019 and 2018, rent expense was $56,672 and ~~2017 was~~ $57,617, ~~and $68,081,~~ respectively.

Note 15 — Enduro Purchase and Sale Agreement

The Company entered into a Purchase and Sale Agreement ("PSA") on May 15, 2018, to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. Contemporaneous with executing the PSA, the Company made a $2.75 million deposit to an acquisition escrow account which was reflected in restricted cash together with earned interest on the Company's June 30, 2018 statement of financial position. On July 20, 2018, the Company was repaid its deposit together with related earned interest as a higher bidder emerged in the Chapter 11 bidding process. In August 2018, upon the closing of a higher bidder's purchase transaction, the Company received payment of a $1.1 million breakup fee under the terms of the PSA. This breakup fee was effectively intended to cover the Company’s Enduro transaction costs, time and effort, substantially all of which occurred before June 30, 2018.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

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 - Quarter

Results of Operations - Year to Date

Liquidity 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.~~Capital Resources

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.~~

Critical Accounting Policies

Executive Overview

General

~~General~~

~~We are engaged primarily in~~Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its stockholders through the ~~development~~ownership, management and ~~production~~development of oil and gas ~~reserves within known~~properties. The Company's long-term goal is to build a diversified portfolio of 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 capital structure with low or minimal leverage, allowing us~~assets primarily through acquisitions, while seeking opportunities to maintain ~~control of~~and increase production through selective development, production enhancement and other exploitation efforts on its properties. Our largest active investment is our ~~assets for the benefit of our stockholders.~~ interest in a CO₂ enhanced oil recovery project in Louisiana's Delhi field.

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.~~stockholders.

~~Our strategy~~In May 2018, our then President and Chief Executive Officer elected to retire as of May 31, 2018. Robert Herlin, our Chairman of the Board, founder and previous CEO, was elected by the board to the position of Executive Chairman and Interim CEO. A special Transition Services Committee of the board was created with one member, William Dozier, to provide additional operational oversight to the Company during the transition to a new CEO. The Nominating and Corporate Governance Committee is working with Mr. Herlin to ~~maximize~~identify candidates and the ~~value realized by our stockholders from our assets, particularly our core Delhi asset.~~

process is expected to be completed during the quarter ending June 30, 2019.

Highlights for our Third Quarter of Fiscal ~~2018~~2019 and Operations Update

"Current quarter" refers to the three months ended March 31, 2019, the Company's third quarter of fiscal 2019.

"Prior quarter" refers to the three months ended December 31, 2018, the Company's second quarter of fiscal 2019.

"Year-ago quarter" refers to the three months ended March 31, 2018, the Company's third quarter of fiscal 2018.

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

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

Highlights for the ~~Quarter:~~Quarter

We paid our twenty-second consecutive quarterly cash dividend on common shares, and declared the next quarterly cash dividend of $0.10 per share payable on June 28, 2019.

Current quarter net income was ~~$3.1~~$2.4 million, or ~~$0.09~~$0.07 per diluted common share, compared to net income of ~~$0.07~~$3.9 million, or $0.12 per diluted common share, in the prior quarter and $3.2 million, or $0.09 per diluted common share, in the year-ago quarter.

We paid our eighteenth consecutive quarterly cash dividend on common shares, in the increased amount of $0.10 per 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.~~

~~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~~$9.5 million for the current quarter, a decrease of 7%14% from the prior quarter and ~~an 8% increase over~~a 7% decrease from the year-ago ~~quarter. Revenues~~quarter, primarily due to a lower realized oil price than in the comparative periods.

General and ~~production were adversely impacted by abnormal sub-freezing weather in January 2018.~~

~~We ended~~administrative expenses decreased 5% to $1.2 million for the current quarter ~~with $28.4 million of working capital, an increase of $0.8 million from~~compared to the prior quarter ~~after paying $3.3~~and decreased 35% from the year-ago quarter.

Working capital increased 9.6% to $31.1 million ~~in common stock dividends.~~compared to year-ago quarter end and we remain debt free.

~~Projects~~

Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2017.

Delhi Field - Enhanced Oil Recovery Project

Our interests in the Delhi field consist of 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 total net revenue interest of 26.2%. The field is operated by Denbury Onshore LLC, a subsidiary of Denbury Resources, Inc. (the "operator").

~~As previously reported, the field had two weather-related disruptions to operations in January 2018 due to abnormal sub-freezing temperatures. Consequently, both~~Net production of oil and NGL averaged 2,016 BOEPD during the quarter which is essentially flat compared to the 2,034 BOEPD during the prior quarter. Gross oil production ~~rates suffered~~at Delhi averaged approximately 6,500 BOPD during the quarter, a 4.4% decrease from ~~multiple days of shut-ins in addition~~the prior quarter. Gross NGL production for quarter was 1,213 BOEPD, up 23% from the prior quarter. Oil production was impacted quarter over quarter due to scheduled ~~downtimes for~~plant maintenance in January. All of the infill producing wells and ~~other repairs both~~all but one injection well were in operation at the end of the quarter. Production is expected to be positively impacted over time as we see response to the new CO₂ injector wells and increases in injections, and we expect the operator to continue generating workover and conformance opportunities. The operator has been successful in facility modifications, improving plant efficiency and minimizing unplanned downtime resulting in improved NGL production in the ~~field~~current quarter and atfurther improvements subsequent to quarter end.

During the current quarter, we incurred $0.7 million on capital projects consisting of $0.3 million for conformance and capital maintenance, $0.2 million primarily for remaining completion costs of a water injection well and a water source well in preparation for Phase V expansion of the flood, and $0.2 million was expended on the NGL ~~plant. However, gross~~plant enhancing flows of richer streams for processing.

In the current quarter, operating revenues were $9.5 million, based on an average realized oil price of $59.12 per barrel and an average realized NGL price of $16.37 per BOE, and we generated $3.0 million in income from operations. The decline in NGL realized prices is directly related to lower oil prices primarily in the first two months of the current quarter together with the Delhi field's ongoing fixed, per barrel post production cost allocation to the field’s royalty and mineral interests, which also reduces our revenue from such interests. This earnings effect is mostly offset by lower lease operating expense for our Delhi working interest that shares in ~~February~~recovered post production costs. In the year-ago quarter, operating revenues were $10.2 million and ~~March returned to normal levels~~we had income from operations of ~~approximately 7,000~~$3.8 million, based on an average realized oil price of $63.56 per barrel and an average realized NGL price of $34.05 per BOE. Net production volumes in the current quarter were 2,016 barrels of oil equivalent per day (“BOEPD”), down slightly from the 2,034 BOEPD in the prior quarter and ~~1,100 barrels of NGL's per day. The Company's net share of production~~up from the year-ago quarter’s 1,884 BOEPD. Net income for the quarter was ~~1,685 BOPD~~$2.4 million, or $0.07 per diluted share, compared to $3.9 million, or $0.12 per diluted share, in the previous quarter and ~~199 barrels of NGL's~~$3.1 million, or $0.09 per ~~day.~~diluted share, in the year-ago quarter.

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 the quarter. We continued to receive a premium price for our crude oil based on Louisiana Light Sweet ("LLS") pricing, but the LLS differential narrowed during the quarter, as did our overall premium to 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 other deductions. Our current mix of products contains a large percentage (~70%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's during the quarter was favorable, with net realized NGL prices averaging approximately 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 $19.82 per barrel of oil equivalent ("BOE") in the current quarter compared to $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 CO~~₂~~expenses resulting from an 11% increase in realized oil prices and higher purchased CO~~₂ ~~volumes. Our total lease operating expenses~~ in the Delhi field were ~~$3.4~~$3.8 million in the current quarter, ~~increasing by $0.4 million~~up 9.9% from the prior quarter and ~~$0.5 million over~~16% from the year-ago quarter. ~~Our purchased CO~~₂ costs increased to $1.5 million ($8.61 per 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, purchasedPurchased CO₂ volumes increased 6%33% compared to the previous quarter and ~~14% , respectively, while our costs~~36% compared to year-ago quarter to 103.3 million cubic feet (MMcf) per ~~Mcf increased as a result~~day due to completion of ~~higher realized oil prices in~~injection wells added by the infill drilling program and returning the field ~~which are directly tied~~ to ~~the price per Mcf for purchased~~optimal pressure. CO₂. purchase costs per mcf were 6% lower than both the previous and year-ago quarters reflecting the lower current quarter realized oil price to which CO₂ cost is linked. The current quarter's oil price was 8.2% and 7.0% lower than those of the previous and year-ago quarters, respectively. Other production costs were virtually flat compared to the previous quarter and were 6.5% higher that the year-ago quarter due primarily to higher fuel gas and chemicals expenses, partially offset by lower electricity expense.

Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.1 of our Form 10-K for the year ended June 30, 2018.

Results of Operations

Three Months Ended March 31, 2019 and 2018

Revenues

Compared to the year-ago quarter, current quarter revenues decreased due to 13% lower realized commodity prices partially offset by an 7% increase in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenue for the three months ended March 31, 2019 and 2018:



	Three Months Ended March 31,
	2019		2018		Variance			Variance %
Oil and gas production
Crude oil revenues	$	9,032,032	$	9,639,238	$	(607,206	)	(6.3	)%
NGL revenues	468,525		511,917		(43,392		)	(8.5	)%
Natural gas revenues	471		—		471			n.m.
Total revenues	$	9,501,028	$	10,151,155	$	(650,127	)	(6.4	)%

Crude oil volumes (Bbl)	152,776		151,665		1,111			0.7	%
NGL volumes (Bbl)	28,626		17,926		10,700			59.7	%
Natural gas volumes (Mcf)	160		—		160			n.m.
Equivalent volumes (BOE)	181,429		169,591		11,838			7.0	%

Crude oil (BOPD, net)	1,698		1,685		13			0.8	%
NGLs (BOEPD, net)	318		199		119			59.8	%
Natural gas (BOEPD, net)	n.m.		—		n.m.			n.m.
Equivalent volumes (BOEPD, net)	2,016		1,884		132			7.0	%

Crude oil price per Bbl	$	59.12	$	63.56	$	(4.44	)	(7.0	)%
NGL price per Bbl	16.37		28.56		(12.19		)	(42.7	)%
Natural gas price per Mcf	2.94		—		2.94			n.m.
Equivalent price per BOE	$	52.37	$	59.86	$	(7.49	)	(12.5	)%

n. m. Not meaningful.

Production Costs

The $0.5 million increase in production costs was due to a 28% increase in CO₂ costs together with a 6.5% increase in other production costs. The $0.1 million increase in other production costs consisted primarily of higher fuel gas and chemicals expenses, partially offset by lower electricity expense.



	Three Months Ended March 31,
	2019		2018		Variance			Variance %
CO₂ costs (a)	$	1,873,720	$	1,459,349	$	414,371		28.4	%
Other production costs	1,919,288		1,802,843		116,445			6.5	%
Total production costs	$	3,793,008	$	3,262,192	$	530,816		16.3	%

CO₂ costs per BOE	$	10.33	$	8.61	$	1.72		20.0	%
All other production costs per BOE	10.58		10.63		(0.05		)	(0.5	)%
Production costs per BOE	$	20.91	$	19.24	$	1.67		8.7	%

(a) 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”),~~Mcf, plus sales taxes of 8%approximately 8.5% and transportation costs of $0.20 per Mcf. ~~Our other (non~~

The $0.4 million increase in CO₂ costs was due to an increase in purchased volumes, partially offset by a lower unit purchase cost reflecting a lower realized oil price.



	Three Months Ended March 31,
	2019		2018		Variance			Variance %
CO₂ costs per mcf	$	0.84	$	0.90	$	(0.06	)	(6.7	)%
CO₂ volumes (MMcf per day, gross)	103.3		75.7		27.6			36.5	%

Depletion, Depreciation and Amortization ("DD&A") ~~lease operating expenses were $1.9 million, up 15% from $1.6 million~~

For the current quarter DD&A was 12.7% higher than the to the year-ago quarter principally because of a 5.3% increase in the ~~prior~~oil and gas properties DD&A rate together with a 7% increase in production volumes.



	Three Months Ended March 31,
	2019		2018		Variance			Variance %
DD&A of proved oil and gas properties	$	1,523,990	$	1,353,340	$	170,650		12.6	%
Depreciation of other property and equipment	4,338		4,153		185			4.5	%
Amortization of intangibles	3,391		3,392		(1		)	—	%
Accretion of asset retirement obligations	26,411		22,263		4,148			18.6	%
Total DD&A	$	1,558,130	$	1,383,148	$	174,982		12.7	%

Oil and gas DD&A rate per BOE	$	8.40	$	7.98	$	0.42		5.3	%

General and Administrative Expenses

Expenses for the current quarter ~~primarily~~decreased $0.6 million, or 35%, to $1.2 million from the year-ago quarter due to a decrease of $0.4 million for litigation expense, which reflected the settlement of a matter in the year-ago quarter, and lower incentive bonus and stock compensation of $0.2 million.

Other Income and Expenses

Other income and expense (net) increased due to higher ~~workover expenses.~~interest income and lower interest expense.



	Three Months Ended March 31,
	2019			2018			Variance		Variance %
Interest and other income	$	65,831		$	21,345		$	44,486	208.4	%
Interest expense	(28,789		)	(30,525		)	1,736		(5.7	)%
Total other income, net	$	37,042		$	(9,180	)	$	46,222	n.m.

Net Income

For the three months ended March 31, 2019, income tax expense was virtually unchanged from the year-ago quarter due to a higher effective tax rate, which reflected a lower benefit from depletion in excess of basis, partially offset by lower income before income taxes.



	Three Months Ended March 31,
	2019			2018			Variance			Variance %
Income before income taxes	$	2,989,997		$	3,654,087		$	(664,090	)	(18	)%
Income tax provision	591,122			585,733			5,389			1	%
Net income available to common stockholders	$	2,398,875		$	3,068,354		$	(669,479	)	(22	)%
Income tax provision (benefit) as a percentage of income before income taxes	20		%	16		%

Results of Operations

Nine Months Ended March 31, 2019 and 2018

Revenues

Compared to the corresponding year-ago period, current period revenues increased 11% due to 14% higher realized commodity prices partially offset by a 2.4% decrease in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the nine months ended March 31, 2019 and 2018:



	Nine Months Ended March 31,
	2019		2018		Variance			Variance %
Oil and gas production
Crude oil revenues	$	30,945,359	$	27,654,128	$	3,291,231		11.9	%
NGL revenues	1,910,395		1,825,214		85,181			4.7	%
Natural gas revenues	471		—		471			n.m.
Total revenues	$	32,856,225	$	29,479,342	$	3,376,883		11.5	%

Crude oil volumes (Bbl)	475,043		496,169		(21,126		)	(4.3	)%
NGL volumes (Bbl)	76,728		69,205		7,523			10.9	%
Natural gas volumes (Mcf)	160		—		160			n.m.
Equivalent volumes (BOE)	551,798		565,374		(13,576		)	(2.4	)%

Crude oil (BOPD, net)	1,734		1,811		(77		)	(4.3	)%
NGLs (BOEPD, net)	280		252		28			11.1	%
Natural gas (BOEPD, net)	n.m.		—		n.m.			n.m.
Equivalent volumes (BOEPD, net)	2,014		2,063		(49		)	(2.4	)%

Crude oil price per Bbl	$	65.14	$	55.74	$	9.40		16.9	%
NGL price per Bbl	24.90		26.37		(1.47		)	(5.6	)%
Natural gas price per Mcf	2.94		—		2.94			n.m.
Equivalent price per BOE	$	59.54	$	52.14	$	7.40		14.2	%

n. m. Not meaningful.

Production Costs

The $1.9 million increase in production costs was due to a 17% increase in other production costs together with a 28% increase in CO₂ costs. The $0.9 million increase in other production costs consisted of higher costs of $0.1 million for the NGL plant expense, $0.3 million for fuel gas expense, $0.2 million for labor, $0.2 million for chemicals and $0.1 million for workovers.



	Nine Months Ended March 31,
	2019		2018		Variance		Variance %
CO₂ costs (a)	$	4,862,502	$	3,813,192	$	1,049,310	27.5	%
Other production costs	5,841,104		4,978,503		862,601		17.3	%
Total production costs	$	10,703,606	$	8,791,695	$	1,911,911	21.7	%

CO₂ costs per BOE	$	8.81	$	6.74	$	2.07	30.7	%
All other production costs per BOE	10.59		8.81		1.78		20.2	%
Production costs per BOE	$	19.40	$	15.55	$	3.85	24.8	%

(a) Under our contract with the operator, purchased CO₂ is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes of approximately 8.5% and transportation costs of $0.20 per Mcf.

The ~~operator commenced~~$1.0 million increase in CO₂costs was due to a 16% increase in purchased volumes together with a 11% increase in price per mcf reflecting the ~~twelve-well infill drilling program in~~higher realized oil price.



	Nine Months Ended March 31,
	2019		2018		Variance		Variance %
CO₂ costs per mcf	$	0.90	$	0.81	$	0.09	11.1	%
CO₂ volumes (MMcf per day, gross)	82.9		71.5		11.4		15.9	%

Depletion, Depreciation and Amortization ("DD&A")

DD&A expense was 2.8% higher compared to the ~~Delhi field in late March as scheduled. Two wells have been drilled~~same year-ago period due to a 5.3% higher oil 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 flowlines and facilities and expects to have the first wells onlinegas DD&A rate which was partially offset by the ~~end of May 2018. This infill program targets productive oil zones~~2.4% decrease in ~~the developed area of the field that the operator believes are not being swept effectively by the current CO~~₂ ~~flood. This program is expected to both add~~ production volumes.



	Nine Months Ended March 31,
	2019		2018		Variance		Variance %
DD&A of proved oil and gas properties	$	4,612,053	$	4,490,545	$	121,508	2.7	%
Depreciation of other property and equipment	12,624		12,578		46		0.4	%
Amortization of intangibles	10,173		10,173		—		—	%
Accretion of asset retirement obligations	75,373		66,865		8,508		12.7	%
Total DD&A	$	4,710,223	$	4,580,161	$	130,062	2.8	%

Oil and gas DD&A rate per BOE	$	8.36	$	7.94	$	0.42	5.3	%

General and ~~increase ultimate recoveries above the current proved producing oil reserves.~~Administrative Expenses

~~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 investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rateExpenses for the ~~current fiscal~~nine months ended March 31, 2019 decreased $1.3 million, or 26%, to $3.8 million from the same year-ago period primarily due to lower stock and incentive compensation of $0.7 million, a $0.6 million decrease in litigation expense and $0.1 million of lower due diligence expense, partially offset by $0.2 million of higher board compensation expenses.

Other Income and Expenses

Other income and expense (net) increased due primarily to the Enduro breakup fee received during August 2018.



	Nine Months Ended March 31,
	2019			2018			Variance			Variance %
Enduro transaction breakup fee	1,100,000			—			1,100,000			n.m.
Interest and other income	172,260			52,036			120,224			231.0	%
Interest expense	(87,479		)	(71,436		)	(16,043		)	22.5	%
Total other income, net	$	1,184,781		$	(19,400	)	$	1,204,181		n.m.

n. m. Not meaningful.

Net Income

Net income available to common stockholders for the nine months ended March 31, 2019 decreased $3.0 million, or 20%, to $12.1 million compared to the same year-ago period primarily due to a non-recurring prior year ~~ended June 30, 2018 is~~deferred tax credit of $6.0 million, partially offset by a ~~blended rate of 27.55%. The permanent reduction~~$3.9 million, or 35%, increase in ~~the federal corporate~~ income ~~tax rate resulted in a one-time non-cash~~before income taxes. This income tax benefit ~~of approximately $6.0 million related to~~resulted from the ~~adjustment~~revaluation of our ~~liability for~~ deferred income ~~taxes to the lower rate in the Tax Act. This benefit was recognized in the quarter ended December 31, 2017. The accounting for the effects of the rate change on the Company’s deferred~~ tax ~~balances was complete as of~~liabilities at December 31, 2017 to reflect the lower federal statutory

rate under the Tax Cut and ~~no provisional amounts were recorded.~~

Jobs Act.

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 %



	Nine Months Ended March 31,
	2019			2018			Variance			Variance %
Income before income taxes	14,866,410			11,009,578			3,856,832			35.0	%
Income tax provision (benefit)	2,767,169			(4,076,156		)	6,843,325			(167.9	)%
Net income available to common stockholders	$	12,099,241		$	15,085,734		$	(2,986,493	)	(19.8	)%
Income tax provision as a percentage of income before income taxes	19		%	(37		)%

~~(a) The~~Excluding the effect of the $6.0 million tax benefit from income ~~tax provision~~taxes for the nine months ended March 31, 2018, ~~includes~~income tax as a ~~one-time non-cash benefit~~percentage of ~~approximately $6.0 million for the adjustment of our liability for deferred~~income before 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.~~would have been approximately 18%. For the nine months ended March 31, 2019 and 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~~respective statutory federal tax rates ~~for~~were 21% and 27.55%, as we used a blended rate during our fiscal 2018 in which the ~~three months~~Tax Cut and ~~the nine months ended March 31, 2018, excluding the impact of the $6.0 million deferred tax adjustment, were lower than the corresponding prior periods as a result~~Jobs Act was enacted. The benefit of the lower statutory ~~tax~~ rate ~~and higher utilization of percentage~~was partially offset by a decreased benefit from depletion in excess of basis ~~during the current year.~~

as much of our depletion carryover had been utilized by June 30, 2018.

Liquidity and Capital Resources

We had ~~$27.2 million and $23.0~~$29.6 million in cash and cash equivalents (and no restricted cash) at March 31, ~~2018~~2019 and $27.7 million of cash, cash equivalents and restricted cash at June 30, ~~2017, respectively.~~2018.

In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of ~~$50.0~~$50 million. The Facility had ~~$40.0~~$40 million of undrawn borrowing base availability on March 31, ~~2018.~~2019. Under the Facility the borrowing base shall be determined semiannually as of May 15 and November 15. There have been no borrowings under the Facility, which matures on April 11, ~~2019~~2021, and it is secured by substantially all of the Company’s assets.

During the current quarter, the bank performed its periodic spring redetermination of borrowing base and confirmed our elected amount of $40 million. Our next scheduled determination will occur this fall.

During the current fiscal year, we amended the credit agreement to broaden the definition for Use of Proceeds to provide funds, limited to an amount not in excess of 25% of the borrowing base, for investments into cash flow generating assets complimentary to the production of oil and gas.

Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants 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 ~~$40.0~~$50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of March 31, ~~2018,~~2019, the Company was in compliance with all covenants contained in the Facility.

During the nine months ended March 31, ~~2018,~~2019, we funded our operations, capital expenditures and cash dividends with cash generated from operations ~~and our cash balance increased $4.2~~resulting in an increase of $1.9 million ~~during that period.~~in cash. As of March 31, ~~2018,~~2019, our working capital was ~~$28.4~~$31.1 million, an increase of ~~$5.0~~$3.4 million over working capital of ~~$23.4~~$27.7 million at June 30, ~~2017.~~2018.

We have historically funded our operations through cash from operations and working capital. Our primary source of cash is the sale of oil and natural gas liquids production. A portion of these cash flows 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. 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~~$40 million of undrawn elected borrowing base 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 up to $500 million of 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~~issue additional equity 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~~twenty-two consecutive quarterly dividends. Distribution of a

substantial portion 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,~~On May 7, 2019, the Board declared ~~an increase in~~ the next quarterly common stock dividend ~~from $0.075 per share to~~of $0.10 per share, ~~effective with the dividend payment in March 2018 and declared a $0.10 per share dividend payable~~which will be paid on June ~~29, 2018.~~28, 2019 to stockholders of record on June 14, 2019. 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 nine months ended March 31, ~~2018,~~2019, we incurred ~~$2.3~~$4.7 million of capital expenditures at Delhi. ~~This~~The current expectation for net capital spending ~~included $0.4~~for the remainder of fiscal 2019 is approximately $0.5 million, and approximately $1.5 million for ~~capital upgrades to~~ the ~~recycle plant, $0.9 million~~first half of fiscal 2020, primarily for CO₂conformance and workover projects and maintenance capital ~~maintenance, $0.7 million~~ for ~~Test Site 5 infrastructure in~~ the ~~eastern portion~~NGL plant. We believe that the operator will continue the development of the field through Phase V in our fiscal years 2020 and ~~$0.3 million for the infill drilling program.~~

The twelve-well infill drilling program in the Delhi field commenced March 2018 and has an estimated net cost of $4.7 million. 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 consists of five new CO₂ ~~injection wells and seven new production wells and targets productive oil zones which we believe are not being swept effectively by the current CO~~₂ ~~flood. It is expected to both add production and increase ultimate recoveries above the current developed producing oil reserves.~~

2021. We have also approved additional net capital expenditures for fiscal 2018 totaling $2.8 million for water injection, flowlines and other infrastructure projects in preparation for the Test Site 5 development. Approximately $0.7 million of these costs have been incurred as of March 31, 2018. In addition, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately at this time, but are not expected to be material to our financial position.

~~Funding~~anticipate funding for our ~~anticipated~~share of capital ~~expenditures~~expenditure 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 was $14.5 million and $11.4 million for the nine months ended March 31, 2018 and 2017, respectively. The approximate $3.2 million increase in cash provided by operations between these two periods resulted from $8.5 million of higher net income and a $1.7 million increase in cash provided by operating assets and liabilities, partially offset by a $7.1 million decrease in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations. ~~This decrease 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 Jobs Act.~~

Net cash used in investing activities was $1.7 million and $10.4 million for the nine months ended March 31, 2018 and 2017, respectively. The decrease in cash outflows was primarily due to $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 nine months ended March 31, 2018 and 2017 was $8.7 million and $14.8 million, respectively. The $6.1 million decrease in cash used was principally due to $7.9 million 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 as a result of increases in dividend rates per share.

~~Full Cost Pool Ceiling Test and Proved Undeveloped Reserves~~

As of 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, 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~~2018 included ~~544~~537 MBOE of reserves and ~~$3.2~~$1.9 million of future development costs associated with ~~a planned~~the infill drilling program and ~~1,564~~1,546 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 program is to increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The project includes both acceleration of production and an increase in ultimate reserve recovery and has been recorded as a proved undeveloped project. The infill project, which was increased from eight wells to twelve wells subsequent to the date of the reserve report, commenced drilling late in the third quarter of fiscal 2018. The timing of ~~our Test Site 5~~Phase V development is dependent in part on the results and CO₂ requirements of the infill drilling 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~~its portfolio of properties. At present, we expect to begin this development in ~~calendar 2019.~~our fiscal year 2020.

Funding for our anticipated capital expenditures at Delhi for our fiscal 2020 is expected to be met from cash flows from operations and current working capital.

~~Three Months Ended March 31, 2018 and 2017~~Overview of Cash Flow Activities

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

Three Months Ended March 31,
2018 2017 Variance Variance %
Oil and gas production:
  Crude oil revenues $ 9,639,238
$ 9,060,796
$ 578,442
6.4 %
  NGL revenues 610,328
464,641
145,687
31.4 %
  Total revenues $ 10,249,566
$ 9,525,437
$ 724,129
7.6 %

  Crude oil volumes (Bbl) 151,665
183,811
(32,146 ) (17.5 )%
  NGL volumes (Bbl) 17,926
19,594
(1,668 ) (8.5 )%
Equivalent volumes (BOE) 169,591
203,405
(33,814 ) (16.6 )%

  Crude oil (BOPD, net) 1,685
2,042
(357 ) (17.5 )%
  NGLs (BOEPD, net) 199
218
(19 ) (8.7 )%
Equivalent volumes (BOEPD, net) 1,884
2,260
(376 ) (16.6 )%

  Crude oil price per Bbl $ 63.56
$ 49.29
$ 14.27
29.0 %
  NGL price per Bbl 34.05
23.71
10.34
43.6 %
    Equivalent price per BOE $ 60.44
$ 46.83
$ 13.61
29.1 %

CO₂ costs
$ 1,459,349
$ 1,049,035
$ 410,314
39.1 %
All other lease operating expenses 1,901,254
1,762,223
139,031
7.9 %
  Production costs $ 3,360,603
$ 2,811,258
$ 549,345
19.5 %
  Production costs per BOE $ 19.82
$ 13.82
$ 6.00
43.4 %
CO₂ volumes (MMcf per day, gross)
75.7
66.3
9.4
14.2 %

Oil and gas DD&A (a) $ 1,353,340
$ 1,515,368
$ (162,028 ) (10.7 )%
Oil and gas DD&A per BOE $ 7.98
$ 7.45
$ 0.53
7.1 %

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

~~Net Income Available to Common Stockholders.~~ ~~During the three months ended March 31, 2018, we generated net income of $3.1 million, or $0.09 per diluted share, on total revenues of $10.2 million. This~~below compares ~~to net income of $2.4 million, or $0.07 per diluted share, on revenues of $9.5 million for the year-ago quarter. The $0.6 million earnings increase reflects~~ a $0.7 million revenue increase, a $0.9 million decline in income taxes primarily attributable to the impact of the 2017 Tax Cuts and Jobs Act, partially offset by $1.0 million of higher operating expenses.

~~Oil and Gas Revenues.~~ ~~Revenues increased 8% to $10.2 million as a result a 29% increase in realized oil and NGL prices to $60.44 per equivalent barrel from $46.83 in the year-ago quarter, partially offset by a~~ ~~16.6%~~ decrease in production volumes. Current quarter NGL and oil production were adversely effected by abnormal sub-freezing temperatures that caused disruptions to our operations and resulted in lost production of approximately seven days of crude oil and over twenty-five days of NGL production 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. Allsummary of our ~~revenues~~condensed consolidated statements of cash flows for ~~the current and year-ago quarters came from the Delhi field.~~

~~Production Costs. Production costs for the current quarter were $3.4 million, a $0.5 million, or 20%, increase from the year-ago quarter, due to higher CO~~₂ ~~costs of $0.4 million, or 39%, together with a $0.1 million, or 8%, increase in other production costs. The CO~~₂ cost increase was due to a higher purchase cost per Mcf, which is correlated with the 29% increase in realized oil price from a year ago, and a 14% increase in purchased volumes. Average gross purchased CO₂ volumes increased from 66.3 MMcf per day in the year-ago quarter to 75.7 MMcf per day for the current quarter. Other production costs, 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 to $19.82 per BOE from $13.82 per BOE in the year-ago quarter due to the purchased CO₂ and other production 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 $26.46 per BOE, of which $11.85 per BOE was CO~~₂cost. 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 $0.6 million, or 44%, to $1.8 million for the three months ended March 31, 2018. The increase resulted primarily from $0.4 million of 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, 2019 and 2018 ~~and 2017, respectively.~~presented on page three of this report on Form 10-Q.

~~Net Income Available to Common Stockholders.~~ ~~During~~



	Nine Months Ended March 31,
Increases (Decreases) in Cash:	2019			2018			Difference
	(In Millions)
Net cash provided by operating activities	$	18.3		$	14.5		$	3.8
Net cash used in investing activities	(6.3		)	(1.6		)	(4.7		)
Net cash used in financing activities	(10.1		)	(8.7		)	(1.4		)
	$	1.9		$	4.2		$	(2.3	)

Cash provided by operating activities in the ~~nine months ended March 31, 2018, we generated net income of $15.1~~current year period increased $3.8 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 attributablecompared to the ~~impact of Tax Cuts~~same year-ago period due to a $5.2 million increase in cash provided by non-cash expenses and ~~Jobs Act,~~$1.6 million increase in cash provided from current operating assets and liabilities partially offset by a ~~$1.3~~$3.0 million decrease in ~~allocated~~cash provided by net income. The year-ago period non-cash items used, rather than provided cash, because of a one-time $6.0 million deferred income tax credit related to ~~holders~~enactment of ~~preferred shares retired~~the Tax Cut and Jobs Act.

Cash used in ~~November 2016,~~investing activities increased $4.7 million due to higher capital expenditure disbursements in the 2019 period.

Cash used by financing activities increased $1.4 million due to $1.7 million of increased cash dividends, reflecting an higher quarterly dividend rate of $0.10 per share in the 2019 period compared to $0.075 per share during the first half of fiscal 2018 and $0.10 per share paid in March 2018, 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 a~~16% 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 CO~~₂ ~~costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO~~₂ ~~costs increased $0.6 million, or 20%, due to higher purchased CO~~₂ ~~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 CO~~₂ 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~~lower common share repurchases related 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 CO~~₂cost. 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-based ~~compensation expense, and $0.3 million of due diligence costs associated with property evaluations.~~

~~Depreciation, Depletion & Amortization Expense (“DD&A”).~~ DD&A increased $0.4 million, or 10%, to $4.5 million for the nine months ended March 31, 2018 compared to the year-ago period primarily due to increased full cost amortization from a higher amortization rate of $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 was principally due to increased 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 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.awards vestings.

~~Off Balance Sheet Arrangements~~Critical Accounting Policies

See our critical accounting policies as disclosed in Note 2– Summary of Significant Accounting Policies in the 2018 Form 10-K. For recently adopted and recently issued accounting pronouncements from the Financial Accounting Standards Board, please see Note 2 – Summary of Significant Accounting Policies herein.

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

~~ITEM~~Item 3. ~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS~~Quantitative and Qualitative Disclosures About Market Risks

Information about market risks for the three months ended March 31, ~~2018,~~2019, 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.~~2018.

Commodity Price Risk

Our most significant market risk is the pricing for crude oil and 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~~Item 4. ~~CONTROLS AND PROCEDURES~~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 Interim 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 Interim Chief Executive Officer and Chief Financial Officer concluded that as of March 31, ~~2018~~2019 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 Interim Chief Executive Officer and Chief Financial Officer, during the quarter ended March 31, ~~2018,~~2019, 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, 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 March 31, 2018 are described in Part I.~~ Item 1. ~~"Financial Information" under Note 14 —~~ ~~Commitments and Contingencies~~ ~~in this Quarterly Report and incorporated herein by reference.~~Legal Proceedings

None.

~~ITEM~~Item 1A. ~~RISK FACTORS~~Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, ~~2017~~2018 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.~~2018.

~~ITEM~~Item 2. ~~UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS~~Unregistered Sales of Equity Securities and Use of Proceeds

~~During the quarter ended 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 March 31, ~~2018,~~2019, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vestings of restricted ~~stock and/or exercises of stock options.~~

stock.

~~ITEM~~Item 3. ~~DEFAULTS UPON SENIOR SECURITIES~~Defaults Upon Senior Securities

Not applicable.

~~ITEM~~Item 4. ~~MINE SAFETY DISCLOSURES~~Mine Safety Disclosures

Not applicable.

~~ITEM~~Item 5. ~~OTHER INFORMATION~~Other Information

None.

~~ITEM~~Item 6. ~~EXHIBITS~~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~~DAVID JOE
		~~Randall D. Keys~~David Joe
		Senior Vice President, ~~and~~ Chief ~~Executive~~Financial Officer and
		Treasurer
Date: May ~~9, 2018~~10, 2019

2724



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

Number of
Contingent
Restricted
Shares

Weighted
Average
Grant-Date
Fair Value

Market-based awards