EVOLUTION PETROLEUM CORP - Quarter Report: 2015 December (Form 10-Q)

Type of Contract

Volumes (in Bbls./day)

Weighted Average Floor Price per Bbl.

Months of January 2016 through March 2016

Fixed Price Swap

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2015

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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Nevada		41-1781991
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

2500 CityWest Blvd., Suite 1300, Houston, Texas 77042

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý No: o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý No: o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o No: ý

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of February 2, 2016, was 32,881,445.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS



		Page

PART I. FINANCIAL INFORMATION		2

ITEM 1.	UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	2

	Unaudited Consolidated Condensed Balance Sheets as of December 31, 2015 and June 30, 2015	2
	Unaudited Consolidated Condensed Statements of Operations for the three and six months ended December 31, 2015 and 2014	3
	Unaudited Consolidated Condensed Statements of Cash Flows for the six months ended December 31, 2015 and 2014	4
	Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the six months ended December 31, 2015	5
	Notes to Unaudited Consolidated Condensed Financial Statements	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26

ITEM 4.	CONTROLS AND PROCEDURES	26

PART II. OTHER INFORMATION		27

ITEM 1.	LEGAL PROCEEDINGS	27

ITEM 1A.	RISK FACTORS	27

ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	28

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	28

ITEM 4.	MINE SAFETY DISCLOSURES	28

ITEM 5.	OTHER INFORMATION	28

ITEM 6.	EXHIBITS	29

SIGNATURES		30

Table of Contents

PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)



	December 31, 2015		June 30, 2015
Assets
Current assets
Cash and cash equivalents	$	16,325,013	$	20,118,757
Receivables	2,557,731		3,122,473
Deferred tax asset	—		82,414
Derivative assets, net	1,323,749		—
Prepaid expenses and other current assets	396,018		369,404
Total current assets	20,602,511		23,693,048
Oil and natural gas property and equipment, net (full-cost method of accounting)	49,049,250		45,186,886
Other property and equipment, net	38,279		276,756
Total property and equipment	49,087,529		45,463,642
Other assets	225,355		726,037
Total assets	$	69,915,395	$	69,882,727
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	4,902,135	$	8,173,878
Accrued liabilities and other	1,262,275		855,373
Derivative liabilities, net	—		109,974
Deferred income taxes	367,661		—
State and federal income taxes payable	342,930		190,032
Total current liabilities	6,875,001		9,329,257
Long term liabilities
Deferred income taxes	10,244,897		11,242,551
Asset retirement obligations	692,976		715,767
Deferred rent	—		18,575
Total liabilities	17,812,874		21,306,150
Commitments and contingencies (Note 16)
Stockholders’ equity
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at December 31, 2015 and June 30, 2015 with a liquidation preference of $7,932,975 ($25.00 per share)	317		317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,881,445 shares and 32,845,205 as of December 31, 2015 and June 30, 2015, respectively	32,881		32,845
Additional paid-in capital	40,063,167		36,847,289
Retained earnings	12,006,156		11,696,126
Total stockholders’ equity	52,102,521		48,576,577
Total liabilities and stockholders’ equity	$	69,915,395	$	69,882,727

See accompanying notes to consolidated condensed financial statements.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)



	Three Months Ended December 31,						Six Months Ended December 31,
	2015			2014			2015			2014
Revenues
Delhi field	$	6,558,215		$	7,644,831		$	13,854,601		$	11,513,433
Artificial lift technology	64,712			63,236			147,732			179,092
Other properties	—			—			—			20,369
Total revenues	6,622,927			7,708,067			14,002,333			11,712,894
Operating costs
Production costs - Delhi field	2,226,141			2,817,866			4,784,028			2,817,866
Production costs - artificial lift technology	53,731			191,553			113,245			388,913
Production costs - other properties	—			9,390			1,046			97,412
Depreciation, depletion and amortization	1,471,571			917,757			2,689,844			1,287,107
Accretion of discount on asset retirement obligations	11,517			8,137			22,860			12,773
General and administrative expenses *	2,057,521			1,606,501			3,742,366			3,111,094
Restructuring charges**	1,257,433			(5,431		)	1,257,433			(5,431		)
Total operating costs	7,077,914			5,545,773			12,610,822			7,709,734
Income (loss) from operations	(454,987		)	2,162,294			1,391,511			4,003,160
Other
Gain on settled derivative instruments, net	1,298,201			—			2,164,628			—
Gain on unsettled derivative instruments, net	361,761			—			1,433,723			—
Delhi field insurance recovery related to pre-reversion event	—			—			1,074,957			—
Interest income	5,853			7,662			11,665			20,425
Interest (expense)	(18,666		)	(12,159		)	(37,126		)	(30,619		)
Income before income taxes	1,192,162			2,157,797			6,039,358			3,992,966
Income tax provision	368,889			917,879			2,123,858			1,624,038
Net income attributable to the Company	823,273			1,239,918			3,915,500			2,368,928
Dividends on preferred stock	168,576			168,576			337,151			337,151
Net income available to common stockholders	$	654,697		$	1,071,342		$	3,578,349		$	2,031,777
Earnings per common share
Basic	$	0.02		$	0.03		$	0.11		$	0.06
Diluted	$	0.02		$	0.03		$	0.11		$	0.06
Weighted average number of common shares
Basic	32,741,166			32,825,631			32,729,705			32,754,016
Diluted	32,802,440			32,947,280			32,789,461			32,884,754

* General and administrative expenses for the three months ended December 31, 2015 and 2014 included non-cash stock-based compensation expense of $212,724 and $245,020, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $430,839 and $488,357, respectively.

** Restructuring charges include $569,228 of non-cash impairment charges and $59,339 of non-cash stock-based compensation for the three months and six months ended December 31, 2015.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)



	Six Months Ended December 31,
	2015			2014
Cash flows from operating activities
Net income attributable to the Company	$	3,915,500		$	2,368,928
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,714,162			1,311,425
Impairments included in restructuring charge	569,228			—
Stock-based compensation	430,839			488,357
Stock-based compensation included in restructuring charge	59,339			—
Accretion of discount on asset retirement obligations	22,860			12,773
Settlements of asset retirement obligations	—			(220,522		)
Deferred income taxes	(547,579		)	656,589
Deferred rent	—			(8,574		)
(Gain) on derivative instruments, net	(3,598,351		)	—
Write-off of deferred loan costs	50,414			—
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales	1,176,758			(1,454,866		)
Receivables other	(9,367		)	(12,492		)
Prepaid expenses and other current assets	(119,515		)	69,697
Accounts payable and accrued expenses	(310,054		)	1,384,201
Income taxes payable	152,898			45,392
Net cash provided by operating activities	4,507,132			4,640,908
Cash flows from investing activities
Derivative settlements received	1,561,979			—
Proceeds from asset sales	—			389,166
Capital expenditures for oil and natural gas properties	(8,650,217		)	(1,136		)
Capital expenditures for other property and equipment	—			(311,075		)
Other assets	(161,345		)	(84,341		)
Net cash used in investing activities	(7,249,583		)	(7,386		)
Cash flows from financing activities
Cash dividends to preferred stockholders	(337,151		)	(337,151		)
Cash dividends to common stockholders	(3,268,319		)	(6,565,350		)
Acquisition of treasury stock	(1,354,743		)	(58,660		)
Tax benefits related to stock-based compensation	3,910,163			921,581
Other	(1,243		)	(11,292		)
Net cash used in financing activities	(1,051,293		)	(6,050,872		)
Net decrease in cash and cash equivalents	(3,793,744		)	(1,417,350		)
Cash and cash equivalents, beginning of period	20,118,757			23,940,514
Cash and cash equivalents, end of period	$	16,325,013		$	22,523,164



Supplemental disclosures of cash flow information:	Six Months Ended December 31,
	2015			2014
Income taxes paid	$	440,000		$	100,000
Louisiana carryback income tax refund and related interest received	$	1,556,999		$	—
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	(2,442,183		)	1,410,420
Deferred loan costs charged to oil and gas property costs	108,472			—
Oil and natural gas property costs incurred through recognition of asset retirement obligations	—			562,482
Settlement of accrued treasury stock purchases	(170,283		)	—
Royalty rights acquired through non-monetary exchange of patent and trademark assets	108,512			—

See accompanying notes to consolidated condensed financial statements.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statement of Changes in Stockholders' Equity

For the Six Months Ended December 31, 2015

(Unaudited)



	Preferred			Common Stock
	Preferred			Common Stock					Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
	Shares	Par Value		Shares		Par Value			Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance at June 30, 2015	317,319	$	317	32,845,205		$	32,845		$	36,847,289		$	11,696,126		$	—		$	48,576,577
Issuance of restricted common stock	—	—		272,098		272			(239		)	—			—			33
Forfeitures of restricted stock	—	—		(31,467	)	(31		)	31			—			—			—
Acquisition of treasury stock	—	—		(204,391	)	—			—			—			(1,184,460		)	(1,184,460		)
Retirements of treasury stock	—	—		—		(205		)	(1,184,255		)	—			1,184,460			—
Stock-based compensation	—	—		—		—			490,178			—			—			490,178
Tax benefits related to stock-based compensation	—	—		—		—			3,910,163			—			—			3,910,163
Net income attributable to the Company	—	—		—		—			—			3,915,500			—			3,915,500
Common stock cash dividends	—	—		—		—			—			(3,268,319		)	—			(3,268,319		)
Preferred stock cash dividends	—	—		—		—			—			(337,151		)	—			(337,151		)
Balance at December 31, 2015	317,319	$	317	32,881,445		$	32,881		$	40,063,167		$	12,006,156		$	—		$	52,102,521

See accompanying notes to consolidated condensed financial statements.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 1 — Organization and Basis of Preparation

Nature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology.

Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2015 Annual Report on Form 10-K for the fiscal year ended June 30, 2015, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

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

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

New Accounting Pronouncement. In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reporting periods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption is permitted. At present, the Company does not believe that adoption of this update will have a material impact on our results of operations, financial position or cash flows.

Note 2 — Restructuring Charge

Separation of GARP Artificial Lift Technology Operations

During the quarter ended December 31, 2015, we conducted a strategic review of our GARP^® artificial lift technology operations and consummated a plan to separate and transfer these operations to a new entity controlled by the inventor of the technology, our Senior Vice President of Operations, and certain former employees of the Company. We invested $108,750 in common and preferred stock of the new entity, Well Lift Inc. ("WLI"). We own 17.5% of WLI and our former employees own the balance of the common stock. Our preferred stock is convertible at our option into common stock which would result in our ownership of 42.5% of WLI, based on the current capital structure of WLI. The company has no contractual exposure to losses of WLI, nor does it have any obligation or agreement to provide additional funding or support to WLI if it is needed. In connection with this transaction, three employees of the Company were terminated. We accrued a restructuring charge based on agreements with the employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for release from liabilities and other provisions including agreements not to compete. Our estimate of accounting charges related to the personnel restructuring as of December 31, 2015 is as follows:

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements



Type of Cost	December 31, 2015
Salary expense	$	530,387
Payroll taxes and benefits expense	98,479
Stock compensation expense	59,339
Personnel restructuring charge	$	688,205

Other Restructuring Impairments

Also in connection with the separation of GARP^®, the Company and WLI entered into an agreement under which we transferred our technology assets, including our patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP^® technology. We reduced the carrying value of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512. This estimate was based on the recent financial results from our artificial lift technology operations and the current depressed state of the oil and gas industry and the potential upside cases were assigned relatively low probabilities for accounting purposes. This resulted in an impairment charge of $469,395. In addition, we transferred certain inventory and minor fixed assets to WLI which had no further use in our operations and were deemed to have negligible market or salvage value. This resulted in impairments of $92,901 to equipment inventory and $6,932 to fixed assets, respectively. These impairments total $569,228 and are included in restructuring charges for the three months ended December 31, 2015.

Note 3 — Receivables

As of December 31, 2015 and June 30, 2015 our receivables consisted of the following:



	December 31, 2015		June 30, 2015
Receivables from oil and gas sales	$	1,945,397	$	3,122,155
Receivable from settled derivatives	602,649		—
Other	9,685		318
Total receivables	$	2,557,731	$	3,122,473

Note 4 — Prepaid Expenses and Other Current Assets

As of December 31, 2015 and June 30, 2015 our prepaid expenses and other current assets consisted of the following:



	December 31, 2015		June 30, 2015
Prepaid insurance	$	133,927	$	178,994
Equipment inventory (a)	—		81,538
Retainers and deposits	26,978		26,978
Prepaid federal and state income taxes	204,694		22,542
Other prepaid expenses	30,419		59,352
Prepaid expenses and other current assets	$	396,018	$	369,404

(a) As discussed in Note 2, our equipment inventory was determined to have no future value in use for our operations and was charged to restructuring costs as part of the separation of our GARP^® artificial lift technology operations.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 5 — Property and Equipment

As of December 31, 2015 and June 30, 2015 our oil and natural gas properties and other property and equipment consisted of the following:



	December 31, 2015			June 30, 2015
Oil and natural gas properties
Property costs subject to amortization	$	64,024,239		$	57,718,653
Less: Accumulated depreciation, depletion, and amortization	(14,974,989		)	(12,531,767		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	$	49,049,250		$	45,186,886
Other property and equipment
Other equipment, at cost	$	337,245		$	607,674
Less: Accumulated depreciation	(298,966		)	(330,918		)
Other equipment, net	$	38,279		$	276,756

During the six months ended December 31, 2015 the Company incurred capital expenditures of $6.3 million for the Delhi field, including approximately $4.4 million for the NGL plant project which is currently in progress. We have incurred approximately $9.4 million on a cumulative basis for the NGL plant out of a total authorized commitment of $24.6 million.

During the three months ended December 31, 2015, we recorded a charge of $210,392 to expense the remaining capitalized costs of certain artificial lift equipment installed in the wells of a third-party customer. We continue to own this equipment and contract rights, but do not expect to realize any significant future value from this investment at current prices.

Note 6 — Other Assets

As of December 31, 2015 and June 30, 2015 other assets consisted of the following:



	December 31, 2015			June 30, 2015
Royalty rights	$	108,512		$	—
Investment in Well Lift Inc., at cost	108,750			—
Trademarks	—			44,803
Patent costs	—			538,276
Less: Accumulated amortization of patent costs	—			(47,063		)
Deferred loan costs	179,468			337,078
Less: Accumulated amortization of deferred loan costs	(171,375		)	(147,057		)
Other assets, net	$	225,355		$	726,037

During the quarter ended September 30, 2015, our plan to obtain a new expanded secured credit facility was postponed due to market conditions. As a result, the Company determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $108,472 of deferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. As discussed in Note 15, the Company is in discussions with the Lender to extend the maturity, renew the current unsecured Credit Agreement or seek a similar source of bank financing. As of December 31, 2015, there were $8,093 of unamortized deferred loan costs related to our existing unsecured credit facility.

See Note 2 for discussion of transactions associated with the separation of our GARP^® artificial lift technology operations.

The company accounts for its investment in WLI using the cost method under which any return of capital reduces cost and any dividends paid are recorded as income. This investment is considered a level 3 fair value measurement and its value will be evaluated for impairment periodically and 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.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 7 — Accrued Liabilities and Other

As of December 31, 2015 and June 30, 2015 our other current liabilities consisted of the following:



	December 31, 2015		June 30, 2015
Accrued incentive and other compensation	$	366,967	$	578,910
Asset retirement obligations due within one year	102,874		57,223
Accrued royalties, including suspended accounts	45,999		75,164
Accrued franchise taxes	63,792		94,885
Accrued restructuring charge	628,866		—
Other accrued liabilities	53,777		49,191
Accrued liabilities and other	$	1,262,275	$	855,373

Note 8 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and

remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a

reconciliation of the beginning and ending asset retirement obligations for the six months ended December 31, 2015, and for the year ended June 30, 2015:



	December 31, 2015			June 30, 2015
Asset retirement obligations — beginning of period	$	772,990		$	352,215
Liabilities incurred (a)	—			564,019
Liabilities settled	—			(137,604		)
Liabilities sold	—			(52,526		)
Accretion of discount	22,860			34,866
Revision of previous estimates	—			12,020
Asset retirement obligations — end of period	$	795,850		$	772,990
Less current portion in accrued liabilities	(102,874		)	(57,223		)
Long-term portion of asset retirement obligations	692,976			715,767

(a) Liabilities incurred during fiscal 2015 relate to our share of the the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.

Note 9 — Stockholders’ Equity

Common Stock Dividends and Buyback Program

Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. During the six months ended December 31, 2015, the Company declared two quarterly dividends on its common stock and paid $3,268,319 to its common stockholders.

On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Commencing in June 2015, 265,762 shares have been repurchased at an average price of $6.05 per share (totaling $1,609,008) including 202,390 shares purchased during the six months ended December 31, 2015, at an average price of $5.80 (totaling $1,173,899). 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. 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 the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Series A Cumulative Perpetual Preferred Stock

At December 31, 2015, there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the holders thereof. Effective July 1, 2014, we can redeem this preferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt. Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $337,151 to holders of our Series A Preferred Stock during each of the six month periods ended December 31, 2015 and 2014.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2015, 100% of cash dividends on preferred stock were treated as qualified dividend income. Approximately 86% of cash dividends on common shares were treated as a return of capital to stockholders and the remainder of 14% were treated as qualified dividend income. Based on our current projections for the fiscal year ending June 30, 2016, we expect all preferred and common dividends will be treated as qualified dividend income.

Note 10 — Stock-Based Incentive Plan

Under the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration on October 24, 2017 and 257,188 shares remain available for grant as of December 31, 2015.

Stock Options

No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. The following summary presents information regarding outstanding Stock Options as of December 31, 2015, and the changes during the period:



	Number of Stock Options and Incentive Warrants		Weighted Average Exercise Price		Aggregate Intrinsic Value (1)		Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at July 1, 2015	91,061		$	2.50
Expired	(5,830	)	4.02
Stock Options outstanding at December 31, 2015	85,231		2.40		$	205,305	0.9
Vested and exercisable at December 31, 2015	85,231		$	2.40	$	205,305	0.9

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($4.81 as of December 31, 2015) and the Stock Option exercise price of in-the-money Stock Options.

Restricted Stock and Contingent Restricted Stock

Prior to August 28, 2014, all Restricted Stock grants contained a four-year vesting period based solely on service. Restricted Stock which vests based solely on service is valued at the fair market value on the date of grant and amortized over the service period.

In August 2014 and in December 2015, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

issued on the date of grant, whereas the Contingent Restricted Stock will be issued only upon the attainment of specified performance-based or market-based vesting provisions.

Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company 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, 2015, certain 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 entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. During the six months ended December 30, 2015, we granted market-based awards with fair values ranging from $2.93 to $5.07, all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance. During fiscal year 2015, we had granted market-based awards with fair values ranging from $4.26 to $8.40 and with expected vesting periods of 3.30 years to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

Unvested Restricted Stock awards at December 31, 2015 consisted of the following:



Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	214,269	7.50
Performance-based awards	120,386	7.92
Market-based awards	93,254	5.50
Unvested at December 31, 2015	427,909	$	7.18

The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2015:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at December 31, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2015	262,227		$	9.37
Service-based shares granted	142,594		6.09
Performance-based shares granted	64,752		6.09
Market-based shares granted	64,752		4.58
Vested	(74,949	)	8.62
Forfeited	(31,467	)	9.39
Unvested at December 31, 2015	427,909		$	7.18	$	2,298,812	2.9

(1) Excludes $559,121 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Unvested Contingent Restricted Stock awards at December 31, 2015 consisted of the following:



Award Type	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	60,196	$	7.92
Market-based awards	46,630	3.34
Unvested at December 31, 2015	106,826	$	5.92

The following table sets forth Contingent Restricted Stock transactions for the six months ended December 31, 2015:



	Number of Contingent Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at December 31, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2015	56,286		$	8.20
Performance-based awards granted	32,376		6.09
Market-based awards granted	32,376		2.93
Forfeited	(14,212	)	8.54
Unvested at December 31, 2015	106,826		$	5.92	$	128,898	3.2

(1) Excludes $476,761 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the three months ended December 31, 2015 and 2014 was $272,063 and $245,020, respectively. For the six months ended December 31, 2015 and 2014, this expense was $490,178 and $488,357, respectively.

Note 11 — Derivatives

In early June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for a substantial portion of its near-term forecasted production to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The costless collars the Company uses to manage risk are designed to establish floor and ceiling prices on anticipated future oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We also use swap agreements in which we exchange our exposure to floating crude spot prices for a fixed price for our production over a period of time.

The Company does not enter into derivative instruments for speculative or trading purposes.

The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedging under which the Company records the fair value of the instruments on the balance sheet at each reporting date with changes in fair value recognized in income. Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings.

These derivative instruments can result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single 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 fair value derivative instruments where the Company is in a net asset position with its counterparty as of December 31, 2015 totaled $1,323,749. Refer to Note 12—Fair Value Measurement for derivative asset and derivative liability balances before offsetting.

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

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.

For the six months ended December 31, 2015, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $3,598,351 consisting of a realized gain of $2,164,628 on settled derivatives and an unrealized net gain of $1,433,723 on unsettled derivatives.

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of December 31, 2015.

Subsequent to December 31, 2015, the Company realized a gain of $677,703 on derivative contracts which expired at the end of January 2016. We had previously recorded an unrealized gain of $483,839 on these contracts as of December 31, 2015.

Note 12 — Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of December 31, 2015. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



	December 31, 2015
Asset (Liability)	Gross Amounts Recognized		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets	$	1,323,749	$	—	$	1,323,749
Current derivative liabilities	—		—		—
Total	$	1,323,749	$	—	$	1,323,749

The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparty's credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.

Note 13 — 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.

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the six months ended December 31, 2015. We believe we have appropriate support for the income tax positions taken and to be taken on our tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2012 through June 30, 2014 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2014 for state tax purposes.

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, with smaller differences related to stock based compensation and other permanent differences. Statutory percentage depletion gives rise to a permanent difference in our tax rates when utilized for state or federal income tax purposes.

In late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We also received $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resulted from the exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we recognized this benefit as an increase in additional paid-in capital for financial reporting purposes. This carryback utilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes. The remaining balance of this net loss carryforward in Louisiana was utilized in the tax return for the year ended June 30, 2015.

We recognized income tax expense of $2,123,858 and $1,624,038 for the six months ended December 31, 2015 and 2014, respectively, with corresponding effective rates of 35% and 41%. The lower effective tax rate in 2015 resulted from a lesser amount of taxable income in the state of Louisiana.

Note 14 — 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,
	2015		2014		2015		2014
Numerator
Net income available to common shareholders	$	654,697	$	1,071,342	$	3,578,349	$	2,031,777
Denominator
Weighted average number of common shares — Basic	32,741,166		32,825,631		32,729,705		32,754,016
Effect of dilutive securities:
Contingent restricted stock grants	9,795		6,432		9,322		1,785
Stock options	51,479		115,217		50,434		128,953
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	32,802,440		32,947,280		32,789,461		32,884,754

Net income per common share — Basic	$	0.02	$	0.03	$	0.11	$	0.06
Net income per common share — Diluted	$	0.02	$	0.03	$	0.11	$	0.06

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



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		At December 31, 2015
Contingent Restricted Stock grants (a)	$	—	46,630
Stock Options	2.40		85,231
	$	1.55	131,861

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

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



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		At December 31, 2014
Contingent Restricted Stock grants (a)	$	—	17,961
Stock Options	2.25		141,061
	$	2.00	159,022

(a) Contingent Restricted Stock grants for which vesting is not considered probable for accounting purposes are excluded from securities outstanding.

Note 15 — Unsecured Revolving Credit Agreement

On February 29, 2012, Evolution Petroleum Corporation entered into a Credit Agreement (the "Credit Agreement") with Texas Capital Bank, N.A. (the "Lender"). The Credit Agreement provides the Company with a revolving credit facility (the “facility”) in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000. A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit.

The facility is unsecured and has a term of four years, expiring on February 29, 2016. The Company's subsidiaries guarantee the Company's obligations under the facility. The proceeds of any loans under the facility may be used by the Company for the acquisition and development of oil and gas properties, as defined in the facility, the issuance of letters of credit, and for working capital and general corporate purposes.

Semi-annually, the borrowing base and a monthly reduction amount are re-determined from reserve reports. Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender’s credit approval process, and are also limited to 25% of the value of our oil and gas properties, as defined in the Credit Agreement.

At the Company's option, borrowings under the facility bear interest at a rate of either (i) an Adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rate or the sum of 0.50% plus the Federal Funds Rate. A maximum of three LIBOR based loans can be outstanding at any time. Allowed loan interest periods are one, two, three and six months. LIBOR interest is payable at the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term. Base Rate interest is payable monthly. Letters of credit bear fees of 3.5% per annum rate applied to the principal amount and are due when transacted. The maximum term of letters of credit is one year.

A commitment fee of 0.50% per annum accrues on unutilized availability and is payable quarterly. The Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as $50,000 in loan costs incurred upon closing.

The Credit Agreement also contains financial covenants including a requirement that the Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1. The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other than permitted indebtedness, and it restricts certain asset sales. Payments of dividends for the Series A Preferred are only restricted by the EBITDA to interest coverage ratio, wherein such dividends are a 1X deduction from EBITDA (as opposed to a 3:1 requirement if dividends were treated as interest expense). The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the Lender may declare any amounts outstanding under the Credit Agreement to be immediately due and payable.

As of December 31, 2015 and 2014, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000, and we are in compliance with all the covenants of the Credit Agreement. During early 2014 the Lender waived the provisions of the Credit Agreement pertaining to the past payments of cash dividends on our common stock, and the Credit Agreement was amended to permit the payment of cash dividends on common stock in the future if no borrowings are outstanding at the time of such payment.

In connection with this agreement, the Company incurred $179,468 of debt issuance costs that have been capitalized in Other Assets and are being amortized on a straight-line basis over the term of the agreement. The unamortized balance in debt

Table of Contents

Evolution Petroleum Corporation And Consolidated Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

issuance costs related to the Credit Agreement was $8,093 as of December 31, 2015. The Company is in discussions with the Lender to extend the maturity, renew the current unsecured Credit Agreement or seek a similar source of bank financing.

Note 16 — 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 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133^rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We also alleged that Denbury’s gross negligence caused certain environmental damage to the unit. Specifically, we allege that Denbury failed to properly conduct CO₂ injection activities. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims, including the assertion that we owe Denbury additional revenue interests pursuant to the 2006 agreements and that our transfers of the reversionary interests from our wholly owned subsidiary to our parent corporation and subsequently to another wholly-owned subsidiary were not timely noticed to Denbury. The Company disagrees with, and is vigorously defending against, Denbury's counterclaims. In March 2015, we amended and expanded our claims in this matter. This matter is set for trial in April 2016.

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. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed certain claims against NGS Sub Corp. The plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and discovery is in process. We will continue to vigorously defend all claims by plaintiffs and consider the likelihood of a material loss to the Company in this matter to be remote.

Lease Commitments. We have a non-cancelable operating lease for office space that expires on July 31, 2016. Future minimum lease commitments as of December 31, 2015 under this operating lease are as follows:



Twelve months ended December 31,
2016	$	92,756

Rent expense for the three months ended December 31, 2015 and 2014 was $45,857 and $43,776, respectively. For the six months ended December 31, 2015 and 2014, rent expense was $90,900 and $87,551.

Capital Expenditures. See Note 5 for discussion of capital projects in progress and expected remaining capital commitments.

Table of Contents

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, 2015 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2015 Annual Report on Form 10-K for the year ended June 30, 2015 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

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

Executive Overview

General

We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our stockholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our stockholders, and a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership in our common stock.

Our strategy is to grow the value of our Delhi asset to maximize the value realized by our stockholders.

We are currently funding our fiscal 2016 capital program from working capital and net cash flows from our properties.

Highlights for our Second Quarter of Fiscal 2016 and Operations Update

"Current quarter" refers to the three months ended December 31, 2015, the Company's 2nd quarter of fiscal 2016.

"Prior quarter" refers to the three months ended September 30, 2015, the Company's 1st quarter of fiscal 2016.

"Year-ago quarter" refers to the three months ended December 31, 2014, the Company's 2nd quarter of fiscal 2015.

Highlights


•	Net income to common shareholders was $0.7 million or $0.02 per diluted common share.


•	Delhi net production increased to 1,801 barrels of oil per day (“BOPD”), a 6% increase over the prior quarter. Gross production in the field increased to 6,810 BOPD from 6,423 BOPD in the prior quarter.


•	Average realized oil price was $39.59 per barrel, down from $46.70 per barrel in the prior quarter, resulting in Delhi revenues of $6.6 million compared to $7.3 million in the prior quarter. Realized hedge gains added $1.3 million, or $7.84 per barrel, which are reported as other income and not included in revenues.

Table of Contents


•	Delhi lifting costs were $13.44 per barrel, an 18% decrease from $16.37 in the prior quarter, due to lower field costs, lower price of CO₂ and reduced volumes of CO₂ purchased for the field.


•	We successfully completed the separation and transfer of our GARP^® artificial lift technology operations, resulting in a one-time personnel restructuring charge of $0.7 million and a non-cash impairment charge of $0.6 million. The recurring annual overhead cost savings to the Company are estimated to be approximately $1.0 million per year.


•	Net working capital remains strong at $13.7 million, and Evolution declared its tenth consecutive quarterly cash dividend on common shares.


•	We remain debt free.

Full Cost Pool Ceiling Test and Proved Undeveloped Reserves

For the quarter ended December 31, 2015, our capitalized costs of oil and gas properties were well below the full cost valuation ceiling and 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 2016. However, lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our petroleum products during the twelve month period ending with the balance sheet date. If commodity prices remain at the current quarter’s lower levels, the average prices used in future ceiling test calculations will decline.

Our proved undeveloped reserves in the Delhi field consist primarily of the NGL plant and development of the remaining eastern part of the field. The estimated future capital expenditures in the Delhi field are $9.34 per BOE of proved undeveloped reserves. The NGL plant is currently under construction and expanded development of the eastern part of the Delhi field was commenced upon the reversion of our working interest in November 2014. Shortly thereafter, the operator reduced its capital budget and temporarily postponed development of the eastern part of the Delhi field. Resumption of this development project is dependent, at least in part, on the operator's allocation of available capital to projects within their portfolio. Both we and the operator believe that it is prudent to complete the NGL plant before continuing with future development of the field as the plant is projected to improve subsequent field economics. At this time, despite lower commodity price levels, we continue to believe that these projects are economically viable and it is probable they will be executed within the next five years. We base our analysis on the current lifting costs in the field and the relatively low future development costs per BOE. Therefore, we believe these reserves remain properly classified as proved undeveloped reserves under SEC guidelines.

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, 2015.

Delhi Field - Enhanced Oil Recovery Project

Gross production at Delhi in the second quarter of fiscal 2016 averaged 6,810 BOPD, an increase of 16% from the year-ago quarter, and a 6% increase from the prior quarter. Net production averaged 1,801 BOPD, a 52% increase from the year-ago quarter, and a 6% increase from prior quarter. The large year-over-year increase in net production volumes was the result of an increase in both gross production volumes and the reversion of our 23.9% working interest in the Delhi field on November 1, 2014, which means we did not realize a full quarter of production associated with our reversionary working interest in the second quarter of fiscal 2015.

Field operating expenses were $13.44 per barrel, an 18% reduction from levels in the prior quarter, resulting primarily from lower purchased CO₂ costs. In the quarter ending December 31, 2015, our net share of the lease operating expenses was approximately $2.2 million, of which $1.0 million is related to CO₂ purchases and transportation expenses. Under our contract with the operator, purchased CO₂ is priced at 1% of the oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of

Table of Contents

8% plus transportation costs of $0.20 per Mcf. CO₂ costs decreased 27% from the prior quarter as result of both lower oil prices and lower purchased CO₂ volumes in the quarter. Purchased CO₂ gross volumes in the current quarter averaged 73,312 Mcf per day, a decline of 18% from 89,705 Mcf per day in the prior quarter. Despite lower purchased CO₂ volumes, the overall oil production has been increasing over the past few quarters. On a total BOE basis, average CO₂ costs were down 31% from $8.89 per BOE in the prior quarter to $6.14 per BOE, as the result of lower CO₂ volumes purchased and lower realized oil prices. Our purchased CO₂costs are substantially correlated with realized oil prices.

Based on recent discussions with the operator, the fabrication, construction and installation of the NGL plant are continuing and completion is anticipated in the fourth quarter of calendar 2016. The plant has a total estimated cost of $24.6 million net to the Company, of which approximately $9.4 million had been incurred as of December 31, 2015. The pace of spending on the NGL plant has been slower than originally projected by the operator, as they have been focused on making the best decisions on design and selection of contractors and have attempted to reduce costs in this current low pricing environment for materials and services required for the plant. Consequently, we believe that our ultimate net costs for the project may be below our initial commitment, however this will not be known until the project is completed. The June 30, 2015 reserves report includes projected peak gross proved production volumes of approximately 1,850 barrels of liquids per day from the NGL plant over the next five years, and peak gross probable volumes of 1,140 barrels of liquids per day later next decade. The methane removed by the plant will be utilized to supply power for the NGL plant and reduce electricity costs for the recycling facility. The NGL plant is also expected to increase the sweep efficiency and recovery of the CO₂ flood, therefore the reserves report reflects incremental gross crude oil production volumes of approximately 500 BOPD once the plant is operational.

GARP^® - Artificial Lift Technology

Based on a strategic review of our GARP^® artificial lift technology operations, we completed the separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the new entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future success of the technology, while eliminating our overhead and operating commitments associated with GARP^®. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.

This transaction resulted in a one-time personnel restructuring charge of $0.7 million, along with non-cash asset impairments of approximately $0.6 million. The separation will reduce our overhead costs by an estimated $1.0 million per year and remove our obligation to fund the future capital and operating needs of this operation.

Liquidity and Capital Resources

We had $16.3 million million and $20.1 million in cash and cash equivalents at December 31, 2015 and June 30, 2015, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility.

During the six months ended December 31, 2015, we funded our operations with cash generated from operations and cash on hand. At December 31, 2015, our working capital was $13.7 million, compared to working capital of $14.4 million at June 30, 2015. The $0.7 million decrease in working capital consists primarily of a $3.8 million reduction in cash, partly offset by a $3.3 million decrease in accounts payable and other changes in working capital.

Cash Flows from Operating Activities

For the six months ended December 31, 2015, cash flows provided by operating activities were $4.5 million, reflecting $3.9 million of cash provided by net income, $0.3 million used by adjustments reconciling net income to cash provided by operating activities, and $0.9 million provided by changes operating assets and liabilities.

For the six months ended December 31, 2014, cash flows provided by operating activities were $4.6 million, which included a small impact from changes in other working capital items. Of the $4.6 million provided, approximately $2.4 million was due to net income, and approximately $2.2 million was attributable to non-cash expenses.

Table of Contents

Cash Flows from Investing Activities

Investing activities for the six months ended December 31, 2015 used $7.2 million of cash, consisting primarily of capital expenditures of approximately $8.7 million for the Delhi field, slightly offset by $1.6 million of derivative settlements received.

Investing activities for the six months ended December 31, 2014 used less than $0.1 million of cash, consisting of capital expenditures of approximately $0.3 million artificial lift technology operations and $0.1 million for GARP^® patent costs, offset by $0.4 million of proceeds received from the sale of properties in the Mississippi Lime project.

Cash Flows from Financing Activities

For the six months ended December 31, 2015, financing activities used $1.1 million of cash, consisting of $3.6 million of dividend payments to common and preferred shareholders and $1.4 million of treasury stock acquisitions, primarily attributable to the Company's share buyback program, which were partially offset by $3.9 million of tax benefits related to stock-based compensation. These tax benefits include a $1.5 million cash refund received from the State of Louisiana for previously filed carryback returns.

During the six months ended December 31, 2014, we used $6.1 million in cash for financing activities, consisting principally of $6.9 million of dividend payments to common and preferred shareholders, offset partially by $0.9 million of cash provided by tax benefits related to stock-based compensation.

Capital Budget

Delhi Field

During the six months ended December 31, 2015, we incurred $6.3 million of capital expenditures, which includes $4.4 million for the NGL recovery plant, $0.8 million for enhancing well bore integrity, $1.0 million for general maintenance capital within the field and $0.1 million of leasehold costs.

As of December 31, 2015, we had incurred approximately $9.4 million of cumulative capital costs for the NGL recovery plant out of an original commitment of $24.6 million. The remaining committed capital costs of approximately $15.2 million are expected to be incurred over the remainder of calendar 2016. In addition, there will likely be other spending on unbudgeted capital projects for maintenance or production enhancement during the current fiscal year, which we do not expect to have a material effect on our financial position.

GARP^® - Artificial Lift Technology

Liquidity Outlook

Funding for our anticipated capital expenditures during this fiscal year is expected to be met from cash flows from operations and current working capital. We expect to remain debt free under our current operating plans, but we have access to a $5.0 million unsecured revolving line of credit. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs. We are currently seeking to renew the unsecured revolving line of credit or a similar source of bank financing.

Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. In June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for approximately two-thirds of its forecasted production from July 1, 2015 to December 31, 2015 to achieve a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. Costless collars used by the Company to manage risk are designed to establish floor and ceiling prices on a part of anticipated future oil production. In October 2015, to reduce exposure

Table of Contents

to oil price volatility for approximately two-thirds of forecasted production from January 1, 2016 to March 31, 2016, we acquired a series of swaps, which provide a fixed price consisting of identical floor and ceiling prices. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth are significantly impacted by the prices we receive for our production. Liquidity could also be affected by any litigation outcome, positive or negative.

The Board of Directors and management instituted a cash dividend on our common stock in December 2013 at an initial quarterly rate of $0.10 per common share. However, as a result of the decline in oil prices which began in the fall of 2014, combined with the anticipated $24.6 million cost of building and installing the Delhi NGL gas plant during calendar years 2015 and 2016, the Board of Directors concluded it was prudent to adjust the quarterly dividend rate from $0.10 per share to $0.05 per share, effective with the quarter ended March 31, 2015. The reduction in the dividend rate allows the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield. In addition, in May 2015, we established a stock repurchase plan to allow us acquire up to $5.0 million of our common stock over time. The actual timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time. Payment of free cash flow in excess of our operating and capital requirements through cash dividends and 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.

Table of Contents

Results of Operations

Three Months Ended December 31, 2015 and 2014

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



	Three Months Ended December 31,
	2015		2014		Variance			Variance %
Delhi field (see note below):
Crude oil revenues	$	6,558,215	$	7,644,831	$	(1,086,616	)	(14.2	)%
Crude oil volumes (Bbl)	165,654		109,200		56,454			51.7	%
Average price per Bbl	$	39.59	$	70.01	$	(30.42	)	(43.5	)%

Delhi field production costs	$	2,226,141	$	2,817,866	$	(591,725	)	(21.0	)%
Delhi field production costs per BOE	$	13.44	$	25.80	$	(12.36	)	(47.9	)%

Artificial lift technology:
Crude oil revenues	$	7,589	$	42,039	$	(34,450	)	(81.9	)%
NGL revenues	685		11,028		(10,343		)	(93.8	)%
Natural gas revenues	317		7,365		(7,048		)	(95.7	)%
Service revenues	56,121		2,804		53,317			1,901.5	%
Total revenues	$	64,712	$	63,236	$	1,476		2.3	%

Crude oil volumes (Bbl)	193		563		(370		)	(65.7	)%
NGL volumes (Bbl)	42		411		(369		)	(89.8	)%
Natural gas volumes (Mcf)	182		2,413		(2,231		)	(92.5	)%
Equivalent volumes (BOE)	265		1,376		(1,111		)	(80.7	)%

Crude oil price per Bbl	$	39.32	$	74.67	$	(35.35	)	(47.3	)%
NGL price per Bbl	16.31		26.83		(10.52		)	(39.2	)%
Natural gas price per Mcf	$	1.74	3.05		(1.31		)	(43.0	)%
Equivalent price per BOE	$	32.42	$	43.92	$	(11.50	)	(26.2	)%

Artificial lift production costs (a)	$	53,731	$	191,553	$	(137,822	)	(71.9	)%
Artificial lift production costs per BOE	$	202.76	$	139.21	$	63.55		45.7	%

Other properties:
Production costs	$	—	$	9,390	$	(9,390	)	(100.0	)%

Combined:
Oil and gas DD&A (b)	$	1,254,350	$	701,543	$	552,807		78.8	%
Oil and gas DD&A per BOE	$	7.56	$	6.34	$	1.22		19.2	%

Note: Results for the three months ended December 31, 2014 do not include revenues, production costs and net volumes from our working interest in the Delhi field prior to reversion on November 1, 2014 and therefore may not be comparable to subsequent periods.

(a) Includes workover costs of approximately $0 and $134,000, for the three months ended December 31, 2015 and 2014, respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $217,221 and $216,214, for the three months ended December 31, 2015 and 2014, respectively.

Table of Contents

Net Income Available to Common Stockholders. For the three months ended December 31, 2015, we generated net income to common shareholders of $0.7 million, or $0.02 per diluted share, on total revenues of $6.6 million. This compares to net income of $1.1 million, or $0.03 per diluted share, on total revenues of $7.7 million for the year-ago quarter. The $0.4 million earnings decrease resulted from a $1.1 million revenue decline and $1.5 million of higher operating expenses (which included a $1.3 million non-recurring restructuring charge), partially offset by $1.7 million of derivative gains and $0.5 million of lower income taxes.

Delhi Field. Revenues decreased 14% to $6.6 million as a result of a 43% decline in realized crude oil prices from $70.01 per barrel to $39.59 per barrel. This was partially offset by a 52% increase in production volumes from the year-ago quarter, which did not reflect a full quarter of production, as reversion of our working interest did not occur until November 1, 2014. Gross production of 6,810 BOPD was 16% higher compared to the year-ago quarter as a result of production enhancement and conformance operations in the field. Production costs for the current quarter were $2.2 million, of which $1.0 million was for CO₂ costs, compared to $2.8 million, of which $1.7 million was for CO₂ costs, in the year-ago quarter. Under our contract with the operator, purchased CO₂ is priced at 1% of the oil price in the field per Mcf plus sales taxes at 8% plus $0.20 per Mcf transportation costs. For the current quarter, production costs were $13.44 per BOE on total production volumes. Production costs were $18.67 per BOE calculated solely on our working interest volumes, which includes $8.53 per working interest BOE for CO₂costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.

Artificial Lift Technology. Revenues of $0.1 million were virtually flat compared to the year-ago quarter. An increase in service revenue was offset by decreased revenue from operated wells. Production volumes declined 81% to 265 BOE and the price per BOE decreased 26% to $32.42. Production costs decreased by approximately $0.1 million, as workover expenses on our operated wells were lower than the year-ago quarter.

General and Administrative Expenses (“G&A”). G&A expenses increased $0.5 million, or 28%, to $2.1 million for the three months ended December 31, 2015 from the year-ago quarter, principally as a result of $0.6 million of higher litigation costs, partially offset by $0.1 million of lower accruals for short-term incentive compensation. Total litigation costs for the quarter were approximately $0.7 million.

Restructuring charge. We recognized a $1.3 million restructuring charge in the current quarter related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of the charge resulted from impairments of assets used in those operations and $0.7 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.

Other Income and Expenses. The Company realized gains of $1.3 million from derivatives that settled during the quarter and $0.4 million from the net change in unsettled derivative positions.

Depletion & Amortization Expense (“DD&A”). DD&A increased $0.6 million, or 60%, to $1.5 million for the current quarter compared to $0.9 million for the year-ago quarter, primarily as a result of $0.6 million of higher amortization of the full cost pool. Production volumes increased 50% to 165,919 BOE and the amortization rate increased 19% to $7.56 per BOE. Compared to the year-ago quarter, the increased amortization rate was impacted by increased future development costs in the June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were previously expected to be borne by the third party operator of the plant and decreases in reserves from the loss of the Philip DL #1 late in fiscal 2015 and from the decision to use produced methane at Delhi internally to generate power thereby lowering field operating costs rather than selling the methane to third party customers.

Table of Contents



	Six Months Ended December 31,
	2015		2014		Variance			Variance %
Delhi field (see note below):
Crude oil revenues	$	13,854,601	$	11,513,433	$	2,341,168		20.3	%
Crude oil volumes (Bbl)	321,890		148,294		173,596			117.1	%
Average price per Bbl	$	43.04	$	77.64	$	(34.60	)	(44.6	)%

Delhi field production costs	$	4,784,028	$	2,817,866	$	1,966,162		69.8	%
Delhi field production costs per BOE	$	14.86	$	19.00	$	(4.14	)	(21.8	)%

Artificial lift technology:
Crude oil revenues	$	37,016	$	117,019	$	(80,003	)	(68.4	)%
NGL revenues	1,735		33,255		(31,520		)	(94.8	)%
Natural gas revenues	1,021		22,917		(21,896		)	(95.5	)%
Service revenues	107,960		5,901		102,059			1,729.5	%
Total revenues	$	147,732	$	179,092	$	(31,360	)	(17.5	)%

Crude oil volumes (Bbl)	873		1,335		(462		)	(34.6	)%
NGL volumes (Bbl)	124		1,155		(1,031		)	(89.3	)%
Natural gas volumes (Mcf)	489		6,852		(6,363		)	(92.9	)%
Equivalent volumes (BOE)	1,078		3,632		(2,554		)	(70.3	)%

Crude oil price per Bbl	$	42.40	$	87.65	$	(45.25	)	(51.6	)%
NGL price per Bbl	13.99		28.79		(14.80		)	(51.4	)%
Natural gas price per Mcf	2.09		3.34		(1.25		)	(37.4	)%
Equivalent price per BOE	$	36.89	$	47.68	$	(10.79	)	(22.6	)%

Artificial lift production costs (a)	$	113,245	$	388,913	$	(275,668	)	(70.9	)%
Artificial lift production costs per BOE	$	105.05	$	107.08	$	(2.03	)	(1.9	)%

Other properties:
Revenues	$	—	$	20,369	$	(20,369	)	(100.0	)%
Equivalent volumes (BOE)	—		285		(285		)	(100.0	)%
Equivalent price per BOE	$	—	$	71.47	$	(71.47	)	(100.0	)%

Production costs	$	1,046	$	97,412	$	(96,366	)	(98.9	)%
Production costs per BOE	n/a		$	341.80	n/a			n/a

Combined:
Oil and gas DD&A (b)	$	2,443,222	$	961,703	$	1,481,519		154.1	%
Oil and gas DD&A per BOE	$	7.56	$	6.32	$	1.24		19.6	%

Note: Results for the six months ended December 31, 2014 do not include revenues, production costs and net volumes from our working interest in the Delhi field prior to reversion on November 1, 2014 and therefore may not be comparable to subsequent periods.

(a) Includes workover costs of approximately $9,901 and $283,000 for the six months ended December 31, 2015 and 2014, respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $246,622 and $325,404 for the six months ended December 31, 2015 and 2014, respectively.

Table of Contents

Net Income Available to Common Stockholders. For the six months ended December 31, 2015, we generated net income to common shareholders of $3.6 million, or $0.11 per diluted share, on total revenues of $14.0 million. This compares to net income of $2.0 million, or $0.06 per diluted share, on total revenues of $11.7 million for the year-ago period. The $1.5 million earnings increase resulted from $2.3 million of higher revenue, $3.5 million of derivative gains, and $1.1 million from an insurance recovery, partially offset by $4.9 million of higher operating expenses (which include a $1.3 million non-recurring restructuring charge) and $0.5 million of higher income taxes.

Delhi Field. Revenues increased 20% to $13.9 million as a result of a 117% increase in production volumes from the year-ago period, partially offset by a 45% decline in realized crude oil prices from $77.64 per barrel to $43.04 per barrel. The year-ago period did not include a full six months of net production, revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Gross production of 6,616 BOPD was 14% higher compared to the year-ago period as a result of production enhancement and conformance operations in the field. Production costs for the current period were $4.8 million, of which $2.4 million was for CO₂ costs, compared to $2.8 million, of which $1.7 million was for CO₂ costs, in the year-ago period. Under our contract with the operator, purchased CO₂ is priced at 1% of the oil price in the field per Mcf plus sales tax at 8% plus $0.20 per Mcf transportation costs. For the six months ended December 31, 2015, production costs were $14.86 per BOE on total production volumes. Production costs were $20.64 per BOE calculated solely on our working interest volumes, which includes $10.38 per working interest BOE for CO₂costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.

Artificial Lift Technology. Revenues declined 18% to $0.1 million as a result of significantly lower revenue on our operated wells, offset by $0.1 million of higher GARP® service revenue. Production volumes decreased 70% to 1,078 BOE and the price per BOE decreased from $47.68 in the prior period to $36.89. Production costs declined by $0.3 million to $0.1 million, compared to $0.4 million in the prior period, primarily as a result of lower workover expenses on our operated wells.

General and Administrative Expenses (“G&A”). G&A expenses increased $0.6 million, or 20% to $3.7 million for the six months ended December 31, 2015 from the year-ago period, principally as a result of an $0.8 million increase in litigation costs and a $0.1 million increase in salaries and payroll benefits, partially offset by $0.3 million of lower accruals for short-term incentive compensation. Total litigation costs for the period were approximately $1.0 million.

Restructuring charge. Effective December 31, 2015, we recognized a $1.3 million restructuring charge related to the separation of our GARP^® artificial lift technology operations. Approximately $0.6 million of the charge consists of the impairment of assets used in that operation and $0.7 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.

Other Income and Expenses. During the six months ended December 31, 2015, the Company realized gains of $2.2 million from derivatives that settled derivatives, $1.4 million for unsettled derivatives and $1.1 million from an insurance recovery at the Delhi field.

Depletion & Amortization Expense (“DD&A”). DD&A increased $1.4 million, or 109% to $2.7 million for the current period compared to $1.3 million for the year-ago period as a result of $1.5 million of higher amortization of the full cost pool, partially offset by lower depreciation on artificial lift technology equipment, miscellaneous fixed assets and other assets. From the year-ago period production volumes increased 112% to 322,968 BOE and the amortization rate increased 20% to $7.56 per BOE. Compared to the year-ago period, the increased amortization rate was impacted by increased future development costs in the June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were previously expected to be borne by the third party operator of the plant and decreases in reserves from the loss of the Philip DL #1 late in fiscal 2015 and from the decision to use produced methane at Delhi internally to generate power thereby lowering field operating costs rather than selling the methane to third party customers.

Other Economic Factors

Inflation. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our production costs and capital expenditures. During fiscal 2014, we saw modest increases in certain oil field services and materials compared to the prior fiscal year. During fiscal 2015 to date, we have not seen material changes in operating costs in wells that we operate, but operating costs in our third

Table of Contents

party operated Delhi field have declined, and we believe such declines are attributable to improved operating efficiencies and generally lower third-party contractor and vendor expenses. 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 demand continues to decrease with a great oversupply in the future, it may continue to put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward.

Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the quarter ending December 31, 2015.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended December 31, 2015, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2015.Commodity Price Risk

Our most significant market risk is the pricing for crude oil, natural gas and NGLs. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, 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 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, 2015 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

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, 2015 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 17 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2015 Annual Report. Material developments in the status of those proceedings during the quarter ended December 31, 2015 are described in Part I. Item 1. "Financial Information" under Note 16 — Commitments and Contingencies in this Quarterly Report and incorporated herein by reference. We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position or on our results of operations.

ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 2015 includes a detailed discussion of our risk factors. In addition to those, we add the following risk factor below:

We are materially dependent upon our operator with respect to the successful operation of our principal asset, which consists of our interests the Delhi Field. A materially negative change in our operator’s financial condition could negatively affect operations in the Delhi Field, and consequently our income from the field as well as the value of our interests in the Delhi Field.

Our royalty, mineral and working interests in the Delhi Field, located in Northeast Louisiana, are currently our most significant asset. Over 99% of our revenues come from these interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations and financial results. We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.

Further, our CO2- Enhanced Oil Recovery (“EOR”) project in the Delhi Field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be invested to fully develop the EOR project, further increase production and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2- EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on us, and our results of operations and financial condition.

Our economic success is thus materially dependent upon the Delhi Field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental, strategic and logistical risks, among other things.

During the fall of 2014, the operator initiated work on expansion of the CO2 flood in the undeveloped eastern part of the field. These operations were suspended by the end of 2014 when the operator made significant cuts in its capital budget as a result of declining oil prices. While we believe that expansion remains economic at current commodity prices, resumption of this work could be electively delayed due to prevailing oil prices and the operator’s allocation of capital for such projects, negatively impacting us.

We are aware that the DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current level of indebtedness and the related financial covenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantial portion of DNR’s cash flow from operations to servicing their indebtedness. They noted that their ability to meet their obligations under their debt instruments will depend in part upon prevailing economic conditions and commodity prices. DNR also noted that it had deferred development spending for certain projects.

Given the current stress in the global commodity markets and oil & gas in particular, our operator could be materially negatively impacted, which could in turn negatively affect the operator’s ability to operate the Delhi Field as well as it’s financial commitment to the EOR project in the field and thus our interests in the Delhi Field could be materially negatively impacted.

Table of Contents

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

During the quarter ended December 31, 2015, the Company did not sell any equity securities that were not registered under the Securities Act.

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2015, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and/or exercises of stock options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting. In addition, during the quarter ended December 31, 2015, the Company repurchased shares of 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 common stock during the quarter ended December 31, 2015.



Period	(a) Total Number of Shares (or Units) Purchased (1) (2)	(b) Average Price Paid per Share (or Units)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Month of October 2015	none	Not applicable	Not applicable	Not applicable
Month of November 2015	18,600	$6.37	Not applicable	$3.4 million
Month of December 2015	10,928	$5.53	Not applicable	$3.4 million

(1)

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 were initially recorded as treasury stock, then subsequently canceled.


(2)	During current quarter the Company received 2,001 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. The acquisition cost per share reflected the weighted-average market price of the Company's shares at the dates vested.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

Table of Contents

ITEM 6. EXHIBITS

A. Exhibits



31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1		Certification of Chief Executive Officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

Table of Contents

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, 2016