EPM Evolution Petroleum Corporation

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PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)  

	December 31, 2017				June 30, 2017
Assets
Current assets
Cash and cash equivalents	$	25,743,497			$	23,028,153
Receivables	4,078,153				2,726,702
Prepaid expenses and other current assets	824,048				387,672
Total current assets	30,645,698				26,142,527
Oil and natural gas property and equipment, net (full-cost method of accounting)	60,093,807				61,790,068
Other property and equipment, net	32,265				40,689
Total property and equipment	60,126,072				61,830,757
Other assets	260,468				295,384
Total assets	$	91,032,238			$	88,268,668
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	2,400,202			$	1,994,255
Accrued liabilities and other	660,467				724,639
Total current liabilities	3,060,669				2,718,894
Long term liabilities
Deferred income taxes	10,580,381				15,826,291
Asset retirement obligations	1,297,028				1,253,628
Total liabilities	14,938,078				19,798,813
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 December 31, 2017 and June 30, 2017, respectively	33,171				33,087
Additional paid-in capital	41,538,133				40,961,957
Retained earnings	34,522,856				27,474,811
Total stockholders’ equity	76,094,160				68,469,855
Total liabilities and stockholders’ equity	$	91,032,238			$	88,268,668

 

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)

 

	Three Months Ended   December 31,								Six Months Ended   December 31,
	2017				2016				2017				2016
Revenues
Crude oil	$	10,185,635			$	8,529,817			$	18,014,890			$	16,123,672
Natural gas liquids	881,276				—				1,589,892				89
Natural gas	—				—				—				(4		)
Total revenues	11,066,911				8,529,817				19,604,782				16,123,757
Operating costs
Production costs	2,914,512				2,292,421				5,806,098				4,637,062
Depreciation, depletion and amortization	1,633,868				1,307,510				3,152,411				2,580,949
Accretion of discount on asset retirement obligations	23,023				13,106				44,602				26,330
General and administrative expenses *	1,666,256				1,241,399				3,235,960				2,476,442
Total operating costs	6,237,659				4,854,436				12,239,071				9,720,783
Income from operations	4,829,252				3,675,381				7,365,711				6,402,974
Other
Gain on realized derivative instruments, net	—				—				—				90
Loss on unrealized derivative instruments, net	—				—				—				(14,132		)
Interest and other income	15,841				14,061				30,691				26,806
Interest expense	(20,456		)		(20,711		)		(40,911		)		(41,056		)
Income before income taxes	4,824,637				3,668,731				7,355,491				6,374,682
Income tax provision (benefit)	(5,052,211		)		1,361,097				(4,661,889		)		2,250,273
Net income attributable to the Company	9,876,848				2,307,634				12,017,380				4,124,409
Dividends on preferred stock	—				—				—				250,990
Deemed dividend on redeemed preferred shares	—				—				—				1,002,440
Net income available to common stockholders	$	9,876,848			$	2,307,634			$	12,017,380			$	2,870,979
Earnings per common share
Basic	$	0.30			$	0.07			$	0.36			$	0.09
Diluted	$	0.30			$	0.07			$	0.36			$	0.09
Weighted average number of common shares
Basic	33,109,448				33,047,166				33,099,546				33,002,088
Diluted	33,140,278				33,083,027				33,140,257				33,037,269

 

* General and administrative expenses for the three months ended December 31, 2017 and 2016 included non-cash stock-based compensation expense of $484,326 and $275,184 , respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $971,810 and $586,872 , respectively.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

 

	Six Months Ended   December 31,
	2017				2016
Cash flows from operating activities
Net income attributable to the Company	$	12,017,380			$	4,124,409
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,180,545				2,609,356
Stock-based compensation	971,810				586,872
Accretion of discount on asset retirement obligations	44,602				26,330
Settlements of asset retirement obligations	—				(121,391		)
Deferred income taxes (benefit)	(5,245,910		)		1,709,519
Loss on derivative instruments, net	—				14,042
Changes in operating assets and liabilities:
Receivables	(1,351,451		)		(462,981		)
Prepaid expenses and other current assets	(436,376		)		(367,039		)
Accounts payable and accrued expenses	(83,013		)		(1,955,546		)
Income taxes payable	—				(311,306		)
Net cash provided by operating activities	9,097,587				5,852,265
Cash flows from investing activities
Derivative settlement payments paid	—				(318,618		)
Capital expenditures for oil and natural gas properties	(1,017,358		)		(7,978,130		)
Capital expenditures for other property and equipment	—				(30,447		)
Net cash used in investing activities	(1,017,358		)		(8,327,195		)
Cash flows from financing activities
Cash dividends to preferred stockholders	—				(250,990		)
Cash dividends to common stockholders	(4,969,335		)		(3,801,962		)
Common share repurchases, including shares surrendered for tax withholding	(395,550		)		(459,858		)
Redemption of preferred shares	—				(7,932,975		)
Other	—				32
Net cash used in financing activities	(5,364,885		)		(12,445,753		)
Net increase (decrease) in cash and cash equivalents	2,715,344				(14,920,683		)
Cash and cash equivalents, beginning of period	23,028,153				34,077,060
Cash and cash equivalents, end of period	$	25,743,497			$	19,156,377

Supplemental disclosures of cash flow information:	Six Months Ended   December 31,
	2017				2016
Income taxes paid	$	1,136,754			$	1,278,773
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	424,365				(1,516,932		)
Oil and natural gas property costs incurred through recognition of asset retirement obligations	(779		)		—

 See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statement of Changes in Stockholders' Equity

For the Six Months Ended December 31, 2017

(Unaudited)

		Common Stock
									Additional Paid-in Capital				Retained Earnings				Treasury Stock				Total Stockholders' Equity
		Shares			Par Value
Balance at June 30, 2017		33,087,308			$	33,087			$	40,961,957			$	27,474,811			$	—			$	68,469,855
Issuance of restricted common stock		158,785			158				(158		)		—				—				—
Forfeitures of restricted stock		(19,561	)		(20		)		20				—				—				—
Common share repurchases, including shares surrendered for tax withholding		(55,018	)		—				—				—				(395,550		)		(395,550		)
Retirements of treasury stock		—			(54		)		(395,496		)		—				395,550				—
Stock-based compensation		—			—				971,810				—				—				971,810
Net income attributable to the Company		—			—				—				12,017,380				—				12,017,380
Common stock cash dividends		—			—				—				(4,969,335		)		—				(4,969,335		)
Balance at December 31, 2017		33,171,514			$	33,171			$	41,538,133			$	34,522,856			$	—			$	76,094,160

 See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

Note 1 — Organization and Basis of Preparation

 

Nature of Operations.   Evolution Petroleum Corporation ("EPM"), together with its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development and production of oil and gas reserves.

 

Interim Financial Statements.   The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2017 Annual Report on Form 10-K for the fiscal year ended June 30, 2017 , as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

 

Principles of Consolidation and Reporting.   Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity.

 

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

New Accounting Pronouncements.

In August 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") by one year and allows entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method. The Company expects that additional disclosures will be required as a result of adopting ASU 2014-09 and is currently assessing the impact of the guidance on its consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01").  The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal years beginning after December 15, 2017. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations. 

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

In February 2016, the FASB issued ASU 2016-02 , Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than twelve months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.

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

Note 2 — Receivables

As of December 31, 2017 and June 30, 2017 , our receivables consisted of the following:

	December 31, 2017				June 30, 2017
Receivables from oil and gas sales	$	4,078,153			$	2,722,880
Other	—				3,822
Total receivables	$	4,078,153			$	2,726,702

Note 3 — Prepaid Expenses and Other Current Assets

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

	December 31, 2017				June 30, 2017
Prepaid insurance	$	86,904			$	169,416
Retainers and deposits	7,589				7,553
Prepaid federal and state income taxes	674,028				121,232
Other prepaid expenses	55,527				89,471
Prepaid expenses and other current assets	$	824,048			$	387,672

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

Note 4 — Property and Equipment

 

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

	December 31, 2017				June 30, 2017
Oil and natural gas properties
Property costs subject to amortization	$	86,403,877			$	84,962,933
Less: Accumulated depreciation, depletion, and amortization	(26,310,070		)		(23,172,865		)
Unproved properties not subject to amortization	—				—
Oil and natural gas properties, net	$	60,093,807			$	61,790,068
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	$	135,377			$	135,377
Less: Accumulated depreciation	(103,112		)		(94,688		)
Other property and equipment, net	$	32,265			$	40,689

 

During the six months ended December 31, 2017 and 2016 , the Company incurred capital expenditures of $1.4 million and $6.5 million , respectively, in the Delhi field.

Note 5 — Other Assets

As of December 31, 2017 and June 30, 2017 , other assets consisted of the following:

	December 31, 2017				June 30, 2017
Royalty rights	$	108,512			$	108,512
Less: Accumulated amortization of royalty rights	(27,128		)		(20,346		)
Investment in Well Lift Inc., at cost	108,750				108,750
Deferred loan costs	168,972				168,972
Less: Accumulated amortization of deferred loan costs	(98,638		)		(70,504		)
Other assets, net	$	260,468			$	295,384

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 the technology. We own 17.5% of the common stock of WLI and account for our investment under the cost method. Any dividends paid are recorded as income and any return of capital reduces our cost basis in the investment. Our investment in WLI is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

Note 6 — Accrued Liabilities and Other

 

As of December 31, 2017 and June 30, 2017 , our other current liabilities consisted of the following:

	December 31, 2017				June 30, 2017
Accrued incentive and other compensation	$	292,382			$	413,113
Accrued severance payments	46,719				—
Asset retirement obligations due within one year	35,539				35,115
Accrued royalties, including suspended accounts	11,524				17,708
Accrued franchise taxes	82,800				150,062
Accrued ad valorem taxes	191,503				108,641
Accrued liabilities and other	$	660,467			$	724,639

 

Note 7 — 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 six months ended December 31, 2017 and for the year ended June 30, 2017 :

	December 31, 2017				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	44,602				59,664
Revision of previous estimates	(778		)		419,072
Asset retirement obligations — end of period	$	1,332,567			$	1,288,743
Less current portion in accrued liabilities	(35,539		)		(35,115		)
Long-term portion of asset retirement obligations	$	1,297,028			$	1,253,628

 

Note 8 — Stockholders’ Equity

  Common Stock

 

As of December 31, 2017 , we had 33,171,514 sh ares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. We paid dividends of $4,969,335 and $3,801,962 to our common shareholders during the six months ended December 31, 2017 and 2016, respectively. These dividend payments consisted of two quarterly dividends of $0.075 per share each during the six months ended December 31, 2017 and quarterly dividend payments of $0.05 and $0.065 per share during the six months ended December 31, 2016.

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 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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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

During the six months ended December 31, 2017 and 2016 , 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:

	Six Months Ended   December 31,
	2017				2016
Number of treasury shares acquired	55,018				73,455
Average cost per share	$	7.19			$	6.26
Total cost of treasury shares acquired	$	395,550			$	459,858

  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 six months ended December 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, all preferred and common dividends were treated for tax purposes as qualified dividend income to recipients. Based on our current projections for the fiscal year ending June 30, 2018, we expect all common dividends for such period to be treated as qualified dividend income. Such projections are based on our reasonable expectations as of December 31, 2017 and are subject to change based on our final tax calculations at the end of the fiscal year.

Note 9 — Stock-Based Incentive Plan

 

At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of December 31, 2017 , 987,845 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.

Restricted Stock and Contingent Restricted Stock

The Company awards grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting

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  Notes to Unaudited Consolidated Condensed Financial Statements

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. Certain awards 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 six months ended December 31, 2017, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employees and 66,944 awards to directors, substantially all of which have a one -year vesting period. We did not grant any performance-based or market based awards, nor any Contingent Restricted Stock awards, during this period.

Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four -year term. As of December 31, 2017 , certain contingent performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period.

Market-based awards vest if the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of indices consisting of either peer companies or a broad market index of companies in our industry. 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.

Unvested Restricted Stock awards at December 31, 2017 consisted of the following:

	Number of Restricted Shares			Weighted Average Grant-Date Fair Value
Service-based awards	220,068			$	6.68
Performance-based awards	50,360			5.67
Market-based awards	50,359			5.44
Unvested Restricted Stock at December 31, 2017	320,787			$	6.33

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

	Number of Restricted Shares			Weighted Average Grant-Date Fair Value				Unamortized Compensation Expense at December 31, 2017				Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	391,624			$	6.22
Service-based shares granted	112,155			6.96
Vested	(163,431	)		6.52
Forfeited	(19,561	)		6.16
Unvested Restricted Stock at December 31, 2017	320,787			$	6.33			$	1,510,203			1.39

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

Unvested Contingent Restricted Stock awards at December 31, 2017 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 December 31, 2017	61,868			$	5.57

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

	Number of Contingent Restricted Shares			Weighted Average Grant-Date Fair Value				Unamortized Compensation Expense at December 31, 2017 (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 December 31, 2017	61,868			$	5.57			$	84,005			1.03

(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.

Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants for the three months ended December 31, 2017 and 2016 was $484,326 and $275,184 , respectively. For the corresponding six month periods, non-cash stock compensation expense was $971,810 and $586,872 , respectively.

Note 10 — Derivatives

From time to time, the Company may use derivative instruments to reduce its exposure to crude oil 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 the payment of dividends on common stock. The Company may use both fixed price swap agreements and costless collars to manage its exposure to crude oil 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. As of June 30, 2017 and December 31, 2017 , the Company had no derivative asset or liability positions.

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

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

For the six months ended December 31, 2017 , the Company had no gains or losses from derivatives. For the six months ended December 31, 2016 , the Company recorded a loss on derivative instruments of $14,042 consisting of a realized gain of $90 on settled positions and an unrealized net loss of $14,132 .

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 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 20% and 35% for the six months ended December 31, 2017 and 2016, respectively. After adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% 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 six months ended December 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 through June 30, 2017 for federal tax purposes and for the years ended June 30, 2013 through June 30, 2017 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

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Evolution Petroleum Corporation And Subsidiaries

  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 December 31,								Six Months Ended December 31,
	2017				2016				2017				2016
Numerator
Net income available to common shareholders	$	9,876,848			$	2,307,634			$	12,017,380			$	2,870,979
Denominator
Weighted average number of common shares — Basic	33,109,448				33,047,166				33,099,546				33,002,088
Effect of dilutive securities:
Contingent restricted stock grants	30,830				9,836				40,711				10,909
Stock options	—				26,025				—				24,272
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,140,278				33,083,027				33,140,257				33,037,269
Net income per common share — Basic	$	0.30			$	0.07			$	0.36			$	0.09
Net income per common share — Diluted	$	0.30			$	0.07			$	0.36			$	0.09

 

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

Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price			At December 31, 2017
Contingent Restricted Stock grants	—			61,868

 

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

Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price				At December 31, 2016
Contingent Restricted Stock grants	$	—			113,270
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 the Company's previous unsecured credit facility which expired in April 2016. The borrowing base under the Facility has been set at $10 million and was subsequently increased to $40 million effective February 1, 2018. As of December 31, 2017 , the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.

Borrowings from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.

The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000 , and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.00% . The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million , all as defined under the Facility.

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Evolution Petroleum Corporation And Subsidiaries

  Notes to Unaudited Consolidated Condensed Financial Statements

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 $70,334 as of December 31, 2017 .

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. The plaintiffs subsequently filed an amended petition joining the Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. The district court dismissed the claim of Mr. Brooks against NGS Sub Corp. and the Company because Mr. Brooks purchased the land where the well is located subsequent to the divestiture of the property by NGS Sub Corp. The claim of Mr. Hawkins is still being defended. A bench trial is currently scheduled for March 2018. We will continue to vigorously defend the claims and based on the input of our legal counsel, we consider the likelihood of a loss in this matter that is material to the financial position of the Company to be remote.

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

Twelve months ended December 31,
2018	$	73,073
2019 (through May)	$	30,447

 

Rent expense for the three months ended December 31, 2017 and 2016 was $19,198 and $18,569 , respectively. Rent expense for the six months ended December 31, 2017 and 2016 was $39,049 and $53,425 , respectively.

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

 

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2017 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10‑K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Certain dollar amounts and percentages in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Quarterly Report on Form 10-Q have been rounded for presentation, and certain amounts may not sum due to rounding.

 

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors.   When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2017 Annual Report on Form 10-K for the year ended June 30, 2017 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

 

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

Executive Overview

 

General

We are engaged primarily in the development and production of oil and gas reserves within known oil and gas resources utilizing conventional technology with a focus on creating value on a per share basis. In doing so, we depend on a capital structure with low or no leverage, allowing us to maintain control of our assets for the benefit of our stockholders. By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this ownership helps ensure that the interests of our employees and directors are aligned with our shareholders.

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

Highlights for our Second Quarter of Fiscal 2018 and Operations Update

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

"Prior quarter" refers to the three months ended September 30, 2017, the Company's first quarter of fiscal 2018.

"Year-ago quarter" refers to the three months ended December 31, 2016, the Company's second quarter of fiscal 2017.

 

Highlights for the Quarter:

•	We reported revenues of $11.1 million for the current quarter, an increase of 30% over both the prior and year-ago quarters.

•	Current quarter net income was $9.9 million, or $0.30 per common share, compared to net income of $0.07 per common share in both the prior and year-ago quarters.

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•	Net income for the current quarter included a one-time $6.0 million non-cash tax benefit related to passage of the Tax Cuts and Jobs Act of 2017.

•	Our realized oil price for the current quarter was $57.30 per barrel, the highest quarterly average since the quarter ended June 30, 2015.

•	We paid our seventeenth consecutive quarterly cash dividend on common shares, in the amount of $0.075 per share, and announced an increase in the quarterly dividend rate to $0.10 per share for the quarter ending March 31, 2018.

•	We ended the current quarter with $27.6 million of working capital, an increase of $3.2 million from the prior quarter, after paying $2.5 million in common stock dividends.

Projects

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

Delhi Field - Enhanced Oil Recovery Project

Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate royalty interests of 7.2%. This yields a total net revenue interest of 26.2%.

Gross oil production at Delhi in the second quarter of fiscal 2018 averaged 7,370 barrels of oil per day ("BOPD"), or 1,932 BOPD net to our interests, a 6.6% increase from the prior quarter and a 2.8% decrease from the year-ago quarter. Oil production in the quarter increased as we put additional existing compression capacity in service and experimented with larger choke sizes to boost the injection of CO ₂ . We also had very few days of scheduled and unscheduled facility downtime compared to the prior quarter. Lastly, we benefited from lower air temperatures, after the high heat of the summer adversely effected production levels.

Gross natural gas liquid ("NGL") sales for this quarter of production were 1,079 barrels of oil equivalent per day ("BOEPD"), or 283 BOEPD net to our interests, up slightly from 1,047 BOEPD in the prior quarter. NGL production rates in the prior quarter were impacted by both planned and unplanned downtime in the field and at the central production facilities. In early August, the plant was shut-in for four days to perform capital upgrades to the inlet of the recycle facility. Results from the NGL plant subsequent to completion of this project have been positive, with the plant operating at or near maximum capacity and efficiency. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane) to increase the purity of the CO ₂ recycle stream and improve the efficiency of the flood. Over time, this is expected to increase the recovery of crude oil in the field. The plant is also producing significant quantities of higher value NGL's for sale as well as providing methane and ethane feedstock to power the electric turbine.

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 and processing fees. There may also be an adjustment for NGL's that do not meet the purchaser's required specifications. The current mix of products contains a large percentage (over 65%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's during the past two quarters has been favorable, with net realized NGL prices averaging approximately 60% of WTI prices. NGL demand often has a seasonal pattern and prices tend to be higher during the cooler months of October through March.

During the extreme cold of January 2018, we experienced two weather-related disruptions to production in the field, including an extended outage at the NGL plant. These issues have been remedied and the field and NGL plant are producing at normal capacity.

       

Field operating expenses were $14.30 per barrel of oil equivalent ("BOE") in the current quarter compared to $15.06 in the prior quarter. Our total lease operating expenses in the Delhi field were $2.9 million in the current quarter, essentially unchanged from the prior quarter, and $0.6 million over the year-ago quarter. Our purchased CO ₂ costs increased to $1.3 million ($6.21 per BOE) from $1.1 million ($5.67 per BOE) in the prior quarter. Purchased CO ₂ volumes were approximately the same in the two periods, but our costs per Mcf increased as a result of higher realized oil prices in the field, which are directly tied to the price per Mcf for purchased CO ₂ . Under our contract with the operator, purchased CO ₂ is priced at 1% of the realized oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of 8% and transportation costs of $0.20 per Mcf. Our other lease operating costs were $1.6 million, down from $1.8 million in the prior quarter.

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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 rate for the current fiscal year ended June 30, 2018 is a blended rate of 27.55% . The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our 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.

	Three Months Ended   December 31,						Six Months Ended   December 31,
	2017			2016			2017			2016
Income before income taxes	4,824,637			3,668,731			7,355,491			6,374,682
Income tax (benefit) provision (a)	(5,052,211	)		1,361,097			(4,661,889	)		2,250,273
Effective tax rate (a)	(105	)%		37	%		(63	)%		35	%

(a) The income tax provision for the three months and six months ended December 31, 2017 includes a one-time non-cash benefit of approximately $6.0 million for the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. This adjustment results in a negative effective tax rate (benefit) for these periods.

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 21% and 37% for the three months ended December 31, 2017 and 2016, respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the quarter ended December 31, 2017 was a tax benefit of (105)% of income before income taxes.

For the six months ended December 31, 2017 and 2016 the effective rates used in the calculation of our income tax expense were approximately 20% and 35% , respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.

Excluding the impact of the $6.0 million deferred tax adjustment, the effective tax rates for the three months and six months ended December 31, 2017 were lower than the corresponding prior periods as a result of the lower statutory tax rate and higher utilization of percentage depletion in excess of basis during the current year.

Liquidity and Capital Resources

We had $25.7 million and $23.0 million in cash and cash equivalents at December 31, 2017 and June 30, 2017, respectively.

In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50.0 million. The Facility had $10.0 million of borrowing base availability on December 31, 2017 and June 30, 2017, respectively. Effective February 1, 2018, the borrowing base and availability under the Facility was expanded to $40.0 million. There have been no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets.

Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. 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 million, each as defined in the Facility. The Facility also contains other affirmative and negative covenants and events of default. As of December 31, 2017, the Company was in compliance with all covenants contained in the Facility.

During the six months ended December 31, 2017 , we funded our operations and cash dividends with cash generated from operations and our cash balance increased $2.7 million during that period. As of December 31, 2017 , our working capital was $27.6 million , an increase of $4.2 million over working capital of $23.4 million at June 30, 2017.

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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. We have access to at least $40 million of availability under our senior secured credit facility if required. In addition we have an effective shelf registration statement with Securities and Exchange Commission under which we may issue new debt or equity securities. If we choose to pursue new growth opportunities, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.

Our other significant use of cash is our on-going dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid seventeen consecutive quarterly dividends. Distribution of free cash flow in excess of our operating and capital requirements through cash dividends and potential repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate. In February 2018, the Board declared an increase in the quarterly common stock dividend from $0.075 per share to $0.10 per share, effective with the dividend payment in March 2018. 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 six months ended December 31, 2017 , we incurred $1.4 million of capital expenditures at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $0.5 million for Phase V infrastructure, $0.4 million for CO ₂ conformance projects and $0.1 million for other capital expenditures.

A twelve-well infill drilling program in the Delhi field has been approved and is planned to commence during the quarter ended March 31, 2018. The infill program has a revised estimated net cost of $4.7 million, the majority of which is expected to be incurred in the remainder of the current fiscal year. The program consists of five new CO ₂ 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. The operator estimates it will take up to five months to drill and complete all the wells.

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 Phase V pattern development. Approximately $0.5 million of these costs have been incurred as of December 31, 2017. 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 for our anticipated capital expenditures at Delhi over the next fiscal year is expected to be met from cash flows from operations and current working capital.

Overview of Cash Flow Activities

Net cash provided by operating activities from operations was $9.1 million and $5.9 million for the six months ended December 31, 2017 and 2016, respectively. The $3.2 million increase in cash provided by operations between these two periods resulted from $7.9 million of higher net income and a $1.2 million increase in cash provided by operating assets and liabilities, partially offset by a $5.9 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 $1.0 million and $8.3 million for the six months ended December 31, 2017 and 2016, respectively. The decrease in cash outflows was primarily due to $7.0 million of lower capital expenditures together with a $0.3 million decline in derivative settlement payments.

Net cash used by financing activities for the six months ended December 31, 2017 and 2016 was $5.4 million and $12.4 million , respectively. The $7.1 million decrease in cash used was principally due to $7.9 million disbursed in the prior fiscal 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 $1.2 million in common share dividends paid as a result of increases in dividend rates per share.

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Full Cost Pool Ceiling Test and Proved Undeveloped Reserves

As of December 31, 2017 , our capitalized costs of oil and gas properties were substantially below the full cost valuation ceiling. We do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarters of fiscal 2018. However, persistent and substantially lower oil prices would have an effect on the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and could adversely impact our ceiling tests in future quarters. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to (the full cost valuation “ceiling”): the estimated future net cash flows from proved oil and gas reserves, discounted at 10%; plus the cost of any properties not being amortized; plus the lower of cost or fair value of unproved properties included in costs being amortized; less the income tax effect related to the differences between the book and tax basis of the properties. If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our petroleum products during the twelve month period ending with the balance sheet date. If commodity prices drop below the average from the past twelve months, future ceiling test calculations would be adversely affected. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future.

Our proved undeveloped reserves at June 30, 2017 included 544 MBOE of reserves and $3.2 million of future development costs associated with a planned infill drilling program and 1,564 MBOE of reserves and $10.9 million of future development costs associated with the Phase V development in the eastern portion of the field. The objective of the infill drilling 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, is expected to begin in the third quarter of fiscal 2018. The timing of our Phase V development is dependent in part on the results and CO ₂ requirement of the infill program. At present, we expect to begin this development in calendar 2019.

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Three Months Ended December 31, 2017 and 2016

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

	Three Months Ended December 31,
	2017				2016				Variance				Variance %
Oil and gas production:
Crude oil revenues	$	10,185,635			$	8,529,817			$	1,655,818			19.4	%
NGL revenues	881,276				—				881,276				n.m.
Total revenues	$	11,066,911			$	8,529,817			$	2,537,094			29.7	%
Crude oil volumes (Bbl)	177,767				182,815				(5,048		)		(2.8	)%
NGL volumes (Bbl)	26,033				—				26,033				n.m.
Equivalent volumes (BOE)	203,800				182,815				20,985				11.5	%
Crude oil (BOPD, net)	1,932				1,987				(55		)		(2.8	)%
NGLs (BOEPD, net)	283				—				283				n.m.
Equivalent volumes (BOEPD, net)	2,215				1,987				228				11.5	%
Crude oil price per Bbl	$	57.30			$	46.66			$	10.64			22.8	%
NGL price per Bbl	33.85				—				33.85				n.m.
Equivalent price per BOE	$	54.30			$	46.66			$	7.64			16.4	%
CO 2  costs	$	1,265,582			$	1,041,741			$	223,841			21.5	%
All other lease operating expenses	1,648,930				1,250,680				398,250				31.8	%
Production costs	$	2,914,512			$	2,292,421			$	622,091			27.1	%
Production costs per BOE	$	14.30			$	12.54			$	1.76			14.0	%
CO 2  volumes (MMcf per day, gross)	69.7				67.0				2.7				4.0	%
Oil and gas DD&A (a)	$	1,626,324			$	1,299,813			$	326,511			25.1	%
Oil and gas DD&A per BOE	$	7.98			$	7.11			$	0.87			12.2	%

n.m. Not meaningful.

(a) Excludes $7,544 and $7,697 of other depreciation and amortization expense for the three months ended December 31, 2017 and 2016, respectively.

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Net Income Available to Common Stockholders. During the three months ended December 31, 2017 , we generated net income of $9.9 million , or $0.30 per diluted share, on total revenues of $11.1 million . This compares to net income of $2.3 million , or $0.07 per diluted share, on revenues of $8.5 million for the year-ago quarter. The $7.6 million earnings increase reflects a $2.5 million revenue increase, a $6.4 million decline in income taxes primarily attributable to the impact of the 2017 Tax Cuts and Jobs Act, partially offset by $1.4 million of higher operating expenses.

Oil and Gas Revenues. Revenues increased 30%  to  $11.1 million as a result of a  11.5% increase in production volumes from the year-ago quarter, together with a  16%  increase in realized oil and NGL prices from  $46.66  per equivalent barrel to  $54.30  per equivalent barrel in the current quarter. All of our revenues for the current and year-ago quarters came from the Delhi field. Net Delhi oil production volumes of 1,932 BOPD decreased 55 BOPD from the year-ago quarter, as a number of highly successful conformance and production enhancement operations in the prior year stabilized at lower rates in the current quarter. Net NGL production averaged 283 BOEPD in the current quarter, at an average sales price of $33.85 per barrel. There were no NGL sales in the year-ago quarter as NGL plant production began in January 2017.

Production Costs . Production costs for the current quarter were $2.9 million , a $0.6 million , or 27% , increase from the year-ago quarter, primarily due to to higher CO ₂ costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO ₂  costs increased $0.2 million , or 21% , due to a higher purchase cost per Mcf, which is derived from the realized field oil price, together with 4% increase in purchase volumes. Average gross purchased CO ₂ volumes increased from 67.0 MMcf per day in the year-ago quarter to 69.7 MMcf per day for the current quarter. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.4 million , or 32% , from the year-ago quarter. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current quarter were $14.30 per BOE on total production volumes, compared to $15.06 per BOE in the year-ago quarter.

Calculated solely on our Delhi working interest volumes, production costs were $18.75 per BOE, of which $8.55 per BOE was CO ₂  cost. 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 $0.4 million , or 34% , to $1.7 million for the three months ended December 31, 2017 as a result of $0.2 million of higher non-cash stock compensation expense, $0.1 million for litigation costs and $0.1 million for due diligence costs associated with property evaluations.

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased $0.3 million , or 25% , to $1.6 million for the current quarter compared to the year-ago period primarily as a result of higher full cost amortization, reflecting an 11% increase in production to 203,800 BOE, together with a 12% higher amortization rate of $7.98 per BOE. The higher rate is principally due to increased development costs.

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Six Months Ended December 31, 2017 and 2016

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

	Six Months Ended December 31,
	2017				2016				Variance				Variance %
Oil and gas production:
Crude oil revenues	$	18,014,890			$	16,123,672			$	1,891,218			11.7	%
NGL revenues	1,589,892				89				1,589,803				n.m.
Natural gas revenues	—				(4		)		4				n.m.
Total revenues	$	19,604,782			$	16,123,757			$	3,481,025			21.6	%
Crude oil volumes (Bbl)	344,504				360,817				(16,313		)		(4.5	)%
NGL volumes (Bbl)	51,279				4				51,275				n.m.
Natural gas volumes (Mcf)	—				16				(16		)		n.m.
Equivalent volumes (BOE)	395,783				360,824				34,959				9.7	%
Crude oil (BOPD, net)	1,872				1,961				(89		)		(4.5	)%
NGLs (BOEPD, net)	279				—				279				n.m.
Natural gas (BOEPD, net)	—				—				—				n.m.
Equivalent volumes (BOEPD, net)	2,151				1,961				190				9.7	%
Crude oil price per Bbl	$	52.29			$	44.69			$	7.60			17.0	%
NGL price per Bbl	31.00				22.25				8.75				39.3	%
Natural gas price per Mcf	—				(0.25		)		0.25				n.m.
Equivalent price per BOE	$	49.53			$	44.69			$	4.84			10.8	%
CO 2  costs	$	2,353,843			$	2,119,874			$	233,969			11.0	%
All other lease operating expenses	3,452,255				2,517,188				935,067				37.1	%
Production costs	$	5,806,098			$	4,637,062			$	1,169,036			25.2	%
Production costs per BOE	$	14.67			$	12.85			$	1.82			14.2	%
CO 2  volumes (MMcf per day, gross)	69.5				70.4				(0.9		)		(1.3	)%
Oil and gas DD&A (a)	$	3,137,205			$	2,565,450			$	571,755			22.3	%
Oil and gas DD&A per BOE	$	7.93			$	7.11			$	0.82			11.5	%

n.m. Not meaningful.

(a) Excludes $15,206 and $15,499 of other depreciation and amortization expense for the six months ended December 31, 2017 and 2016 , respectively.

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Net Income Available to Common Stockholders. During the six months ended December 31, 2017 , we generated net income of $12.0 million , or $0.36 per diluted share, on total revenues of $19.6 million . This compares to net income of $2.9 million , or $0.09 per diluted share, on revenues of $16.1 million for the six months ended December 31, 2016 .  The $9.1 million earnings increase reflects higher revenues of $3.5 million , an income tax decrease of $6.9 million primarily attributable to the impact of Tax Cuts and Jobs Act, and a $1.2 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $2.5 million of higher operating expenses.

Oil and Gas Revenues. Revenues increased 22%  to  $19.6 million as a result of a  10% increase in production volumes over the prior year period, together with a  11%  increase in realized prices from  $44.69  per equivalent barrel to  $49.53  per equivalent barrel. All of our revenues in the current fiscal year came from the Delhi field, as well as virtually all of our revenues from the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD from the prior year period. Net NGL production averaged 279 BOEPD, at an average price of $31.00 per barrel. There were no NGL sales in the year-ago period as NGL plant production began in January 2017.

Production Costs . Production costs for the current year period were $5.8 million , a $1.2 million , or 25% , 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 $0.2 million , or 11% , due to higher purchase cost per Mcf, which is derived from the realized field oil price, partially offset by a slight 1% decline in purchase volumes. Average gross purchased CO ₂ volumes decreased from 70.4 MMcf per day in the year-ago period to 69.5 MMcf per day for the current year. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.9 million , or 37% , from the year-ago period. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current period were $14.67 per BOE on total production volumes, compared to $12.85 in the prior year period.

Calculated solely on our Delhi working interest volumes, production costs were $19.24 per BOE, of which $8.19 per BOE was CO ₂  cost. 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 $0.8 million , or 31% , to $3.2 million for the six months ended December 31, 2017 . The increase in expense included $0.4 million of non-cash stock-based compensation expense, $0.1 million of severance costs, $0.1 million of litigation expense, $0.1 million of due diligence costs associated with property evaluations, and $0.1 million of higher board of director expenses.

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased $0.6 million , or 22% , to $3.2 million for the current period compared to the year-ago period primarily due to higher full cost amortization, reflecting a 10% increase in production to 395,783 BOE, together with a 12% higher amortization rate of $7.93 per BOE. The higher rate is 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 quarter than any period since the quarter ended June 30, 2015, 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.

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Off Balance Sheet Arrangements

 

The Company had no off-balance sheet arrangements to report for the quarter ended December 31, 2017 .

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

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 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2017 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended December 31, 2017 , 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.

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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 December 31, 2017 are described in Part I. Item 1. "Financial Information" under Note 14 — Commitments and Contingencies in this Quarterly Report and incorporated herein by reference. We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position.

ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 2017 includes a detailed description of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2017.

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

During the quarter ended December 31, 2017 , the Company did not sell any equity securities that were not registered under the Securities Act.

Issuer Purchases of Equity Securities

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

Period		(a) Total Number of Shares Purchased (1)		(b) Average Price Paid per Share(1)		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		(d) Maximum  Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 2017		2,471		$7.03		Not applicable		$3.4 million
November 2017		29,001		$7.20		Not applicable		$3.4 million
December 2017		8,262		$7.10		Not applicable		$3.4 million
Total		39,734		$7.17		Not applicable		$3.4 million

(1) During the current quarter the Company received shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

A.             Exhibits

4.1			Form of Restricted Stock Agreement under 2016 Equity Incentive Plan (filed herein)
4.2			Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan (filed herein)
10.1			Second Amendment to Credit Agreement and Assumption Agreement to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective February 1, 2018 (filed herein)
31.1			Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2			Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1			Certification of Chief Executive Officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS			XBRL Instance Document
101.SCH			XBRL Taxonomy Extension Schema Document
101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF			XBRL Taxonomy Extension Definition Linkbase Document
101.LAB			XBRL Taxonomy Extension Label Linkbase Document
101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

EVOLUTION PETROLEUM CORPORATION

(Registrant)

 

 

		By:	/s/ RANDALL D. KEYS
			Randall D. Keys
			President and Chief Executive Officer
Date: February 8, 2018

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