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 September 30, 2014March 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 November 4, 2014,May 5, 2015, was 32,797,644.32,909,331.


EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
 
TABLE OF CONTENTS
 
  Page
   
PART I. FINANCIAL INFORMATION
2
   
ITEM 1.
UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
2
   
 
Unaudited Consolidated Condensed Balance Sheets as of September 30, 2014March 31, 2015 and June 30, 2014
2
 
Unaudited Consolidated Condensed Statements of Operations for the three months ended September 30,March 31, 2015 and 2014 and 2013the nine months ended March 31, 2015 and 2014
3
 
Unaudited Consolidated Condensed Statements of Cash Flows for the threenine months ended September 30,March 31, 2015 and 2014 and 2013
4
 
Unaudited Consolidated Condensed Statement of Stockholders’ Equity for the threenine months ended September 30, 2014March 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
1417
   
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
1925
   
ITEM 4.
CONTROLS AND PROCEDURES
1925
   
PART II. OTHER INFORMATION
2026
   
ITEM 1.
LEGAL PROCEEDINGS
2026
   
ITEM 1A.
RISK FACTORS
2126
   
ITEM 2.
UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
2126
   
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
2126
   
ITEM 4.
MINE SAFETY DISCLOSURES
2126
   
ITEM 5.
OTHER INFORMATION
2126
   
ITEM 6.
EXHIBITS
2227
   
SIGNATURES
 
2328



1
Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited) 


September 30,
2014		 June 30,
2014		March 31,
2015		 June 30,
2014
Assets 
  
 
  
Current assets 
  
 
  
Cash and cash equivalents$21,368,144
 $23,940,514
$20,391,495
 $23,940,514
Receivables 
  
2,686,686
 1,457,212
Oil and natural gas sales1,268,122
 1,456,146
Other23,524
 1,066
Deferred tax asset159,624
 159,624
159,624
 159,624
Prepaid expenses and other current assets632,706
 747,453
650,826
 747,453
Total current assets23,452,120
 26,304,803
23,888,631
 26,304,803
Oil and natural gas property and equipment, net (full-cost method of accounting)37,651,450
 37,822,070
40,349,940
 37,822,070
Other property and equipment, net444,942
 424,827
308,411
 424,827
Total property and equipment38,096,392
 38,246,897
40,658,351
 38,246,897
Other assets527,341
 464,052
662,247
 464,052
Total assets$62,075,853
 $65,015,752
$65,209,229
 $65,015,752
Liabilities and Stockholders’ Equity 
  
 
  
Current liabilities 
  
 
  
Accounts payable$611,547
 $441,722
$4,556,114
 $441,722
State and federal income taxes payable44,173
 —
116,343
 —
Accrued liabilities and other874,013
 2,558,004
789,692
 2,558,004
Total current liabilities1,529,733
 2,999,726
5,462,149
 2,999,726
Long term liabilities 
  
 
  
Deferred income taxes10,021,875
 9,897,272
10,834,844
 9,897,272
Asset retirement obligations209,028
 205,512
749,252
 205,512
Deferred rent31,434
 35,720
22,861
 35,720
Total liabilities11,792,070
 13,138,230
17,069,106
 13,138,230
Commitments and contingencies (Note 12)

 

Commitments and contingencies (Note 15)

 

Stockholders’ equity 
  
 
  
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at September 30, 2014 and June 30, 2014 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 32,797,743 shares and 32,615,646 as of September 30, 2014 and June 30, 2014, respectively32,797
 32,615
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 March 31, 2015 and June 30, 2014 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 32,909,331 shares and 32,615,646 as of March 31, 2015 and June 30, 2014, respectively32,909
 32,615
Additional paid-in capital35,357,362
 34,632,377
36,489,885
 34,632,377
Retained earnings14,893,307
 17,212,213
11,617,012
 17,212,213
Total stockholders’ equity50,283,783
 51,877,522
48,140,123
 51,877,522
Total liabilities and stockholders’ equity$62,075,853
 $65,015,752
$65,209,229
 $65,015,752
 

See accompanying notes to consolidated condensed financial statements.

2
Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
 
Three Months Ended 
 September 30,		Three Months Ended 
 March 31,		 Nine Months Ended 
 March 31,
2014 20132015 2014 2015 2014
Revenues 
  
 
  
  
  
Delhi field$3,868,602
 $4,429,811
$7,039,868
 $4,185,156
 $18,553,301
 $12,745,203
Artificial lift technology115,856
 142,091
24,821
 151,052
 203,913
 483,037
Other properties20,369
 61,797
—
 798
 20,369
 134,754
Total revenues4,004,827
 4,633,699
7,064,689
 4,337,006
 18,777,583
 13,362,994
Operating costs 
  
 
  
  
  
Production costs - Delhi field2,932,946
 —
 5,750,812
 —
Production costs - artificial lift technology197,360
 163,749
267,906
 209,742
 656,819
 526,712
Production costs - other properties88,022
 254,501
639
 143,887
 98,051
 481,697
Depreciation, depletion and amortization369,350
 309,673
1,138,502
 311,815
 2,425,609
 948,656
Accretion of discount on asset retirement obligations4,636
 12,928
10,924
 9,631
 23,697
 34,977
General and administrative expenses *1,504,593
 1,928,951
1,467,782
 2,304,397
 4,578,876
 6,875,430
Restructuring charges **—
 —
 (5,431) 1,332,186
Total operating costs2,163,961
 2,669,802
5,818,699
 2,979,472
 13,528,433
 10,199,658
Income from operations1,840,866
 1,963,897
1,245,990
 1,357,534
 5,249,150
 3,163,336
Other 
  
 
  
  
  
Interest income12,763
 7,703
7,401
 7,383
 27,826
 22,787
Interest (expense)(18,460) (16,513)(24,625) (17,605) (55,244) (50,700)
Net income before income taxes1,835,169
 1,955,087
Income before income taxes1,228,766
 1,347,312
 5,221,732
 3,135,423
Income tax provision706,159
 482,636
494,180
 423,612
 2,118,218
 1,148,155
Net income attributable to the Company$1,129,010
 $1,472,451
$734,586
 $923,700
 $3,103,514
 $1,987,268
Dividends on preferred stock168,575
 168,575
168,575
 168,575
 505,726
 505,726
Net income available to common stockholders$960,435
 $1,303,876
$566,011
 $755,125
 $2,597,788
 $1,481,542
Earnings per common share          
Basic$0.03
 $0.05
$0.02
 $0.02
 $0.08
 $0.05
Diluted$0.03
 $0.04
$0.02
 $0.02
 $0.08
 $0.05
Weighted average number of common shares 
  
 
  
  
  
Basic32,682,401
 28,607,320
32,861,001
 32,358,163
 32,789,157
 30,328,344
Diluted32,826,250
 32,211,265
32,958,218
 32,732,049
 32,909,981
 32,503,460
 
* General and administrative expenses for the three months ended September 30,March 31, 2015 and 2014 and 2013 included non-cash stock-based compensation expense of $243,337$227,507 and $373,438,$444,981, respectively. For the corresponding nine month periods, non-cash stock-based compensation expense was $715,864 and $1,134,841, respectively. 


** Restructuring charges for the nine months ended March 31, 2014 included non-cash stock-based compensation expense of $376,365. For the three months ended March 31, 2014, restructuring charges contained no stock-based compensation expense.

See accompanying notes to consolidated condensed financial statements.


3
Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
 
Three Months Ended 
 September 30,		Nine Months Ended 
 March 31,
2014 20132015 2014
Cash flows from operating activities 
  
 
  
Net income attributable to the Company$1,129,010
 $1,472,451
$3,103,514
 $1,987,268
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Depreciation, depletion and amortization381,509
 319,885
2,462,087
 980,589
Stock-based compensation243,337
 373,438
715,864
 1,134,841
Stock-based compensation related to restructuring—
 376,365
Accretion of discount on asset retirement obligations4,636
 12,928
23,697
 34,977
Settlements of asset retirement obligations(226,008) —
(223,565) (73,646)
Deferred income taxes124,603
 72,395
937,572
 998,367
Deferred rent(4,286) (4,286)(12,859) (12,859)
Changes in operating assets and liabilities: 
  
 
  
Receivables from oil and natural gas sales188,024
 11,133
(1,007,058) 88,146
Receivables from income taxes and other(22,458) 918
Receivables other(222,416) (3,679)
Due from joint interest partner—
 (14,614)—
 70,083
Prepaid expenses and other current assets114,747
 53,948
96,627
 (376,501)
Accounts payable and accrued expenses(1,345,875) (1,146,080)629,760
 690,360
Income taxes payable44,173
 404,677
116,343
 (233,548)
Net cash provided by operating activities631,412
 1,556,793
6,619,566
 5,660,763
Cash flows from investing activities 
  
 
  
Proceeds from asset sales—
 66,753
389,166
 542,349
Maturity of certificate of deposit—
 250,000
Capital expenditures for oil and natural gas properties(1,136) (594,214)(2,432,424) (989,616)
Capital expenditures for other property and equipment(156,798) —
(320,936) (12,793)
Other assets(55,046) (1,913)(183,877) (181,751)
Net cash used in investing activities(212,980) (529,374)(2,548,071) (391,811)
Cash flows from financing activities 
  
 
  
Proceeds on exercise of stock options141,600
 3,162,801
Cash dividends to preferred stockholders(168,575) (168,575)(505,726) (505,726)
Cash dividends to common stockholders(3,279,341) —
(8,192,989) (6,462,269)
Acquisitions of treasury stock(55,452) (117,182)
Stock exchanged for payroll tax liabilities(63,556) (1,591,765)
Tax benefits related to stock-based compensation537,282
 —
1,063,827
 108,473
Recovery of short swing profits—
 6,850
Deferred loan costs(24,716) —
(63,737) (40,334)
Other67
 6,850
Net cash used in financing activities(2,990,802) (278,907)(7,620,514) (5,321,970)
Net increase (decrease) in cash and cash equivalents(2,572,370) 748,512
Net decrease in cash and cash equivalents(3,549,019) (53,018)
Cash and cash equivalents, beginning of period23,940,514
 24,928,585
23,940,514
 24,928,585
Cash and cash equivalents, end of period$21,368,144
 $25,677,097
$20,391,495
 $24,875,567

Supplemental disclosures of cash flow information:
Three Months Ended 
 September 30,
Supplemental disclosures of cash flow information:Nine Months Ended 
 March 31,
2014 20132015 2014
Income taxes paid$—
 $—
$100,000
 $755,941
Non-cash transactions: 
  
 
  
Change in accounts payable used to acquire property and equipment(31,806) (136,436)1,877,830
 (241,094)
Oil and natural gas property costs incurred through recognition of asset retirement obligations—
 45,172
573,689
 45,172
Previously acquired Company common shares swapped by holders to pay stock option exercise price—
 618,606
 
See accompanying notes to consolidated condensed financial statements.

4
Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statement of Changes in Stockholders' Equity
For the ThreeNine Months Ended September 30, 2014March 31, 2015
(Unaudited)

Preferred Common Stock        Preferred Common Stock        
Additional
Paid-in
Capital		 Retained
Earnings		 Treasury
Stock		 Total
Stockholders'
Equity		Additional
Paid-in
Capital		 Retained
Earnings		 Treasury
Stock		 Total
Stockholders'
Equity
Shares Par Value Shares Par Value Shares Par Value Shares Par Value 
Balance, June 30, 2014317,319
 $317
 32,615,646
 $32,615
 $34,632,377
 $17,212,213
 $—
 $51,877,522
317,319
 $317
 32,615,646
 $32,615
 $34,632,377
 $17,212,213
 $—
 $51,877,522
Issuance of restricted common stock—
 —
 187,726
 188
 (188) —
 —
 —
—
 —
 213,466
 214
 (147) —
 —
 67
Acquisitions of treasury stock—
 —
 (5,629) —
 —
 —
 (55,452) (55,452)
Exercise of stock options—
 —
 87,000
 87
 141,513
 —
 —
 141,600
Stock exchanged for payroll tax liabilities—
 —
 (6,781) —
 —
 —
 (63,556) (63,556)
Retirements of treasury stock—
 —
 —
 (6) (55,446) —
 55,452
 —
—
 —
 —
 (7) (63,549) —
 63,556
 —
Stock-based compensation—
 —
 —
 —
 243,337
 —
 —
 243,337
—
 —
 —
 —
 715,864
 —
 —
 715,864
Tax benefits related to stock-based compensation—
 —
 —
 —
 537,282
 —
 —
 537,282
—
 —
 —
 —
 1,063,827
 —
 —
 1,063,827
Net income—
 —
 —
 —
 —
 1,129,010
 —
 1,129,010
Net income attributable to the Company—
 —
 —
 —
 —
 3,103,514
 —
 3,103,514
Common stock cash dividends—
 —
 —
 —
 —
 (3,279,341) —
 (3,279,341)—
 —
 —
 —
 —
 (8,192,989) —
 (8,192,989)
Preferred stock cash dividends—
 —
 —
 —
 —
 (168,575) —
 (168,575)—
 —
 —
 —
 —
 (505,726) —
 (505,726)
Balance, September 30, 2014317,319
 $317
 32,797,743
 $32,797
 $35,357,362
 $14,893,307
 $—
 $50,283,783
Balance, March 31, 2015317,319
 $317
 32,909,331
 $32,909
 $36,489,885
 $11,617,012
 $—
 $48,140,123



 See accompanying notes to consolidated condensed financial statements.


5
tableTable of contentsContents
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" "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 incremental 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 2014 Annual Report on Form 10-K for the fiscal year ended June 30, 2014, 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.



6
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 2 — Receivables

As of March 31, 2015 and June 30, 2014 our receivables consisted of the following:

 March 31,
2015		 June 30,
2014
Receivables from oil and gas sales$2,463,204
 $1,456,146
Receivable from insurer recovering litigation costs206,895
 —
Other16,587
 1,066
Total receivables$2,686,686
 $1,457,212

Note 3 — Prepaid Expenses and Other Current Assets

As of March 31, 2015 and June 30, 2014 our prepaid expenses and other current assets consisted of the following:

 March 31,
2015		 June 30,
2014
Prepaid insurance$93,497
 $169,288
Equipment inventory34,984
 85,888
Prepaid other63,634
 42,800
Retainers and deposits26,978
 29,478
Prepaid federal and Louisiana income taxes431,733
 419,999
Prepaid expenses and other current assets$650,826
 $747,453



Note 24 — Property and Equipment
 
As of September 30, 2014March 31, 2015 and June 30, 2014 our oil and natural gas properties and other property and equipment consisted of the following:
September 30,
2014		 June 30,
2014		March 31,
2015		 June 30,
2014
Oil and natural gas properties 
  
 
  
Property costs subject to amortization$47,167,417
 $47,166,282
$51,722,157
 $47,166,282
Less: Accumulated depreciation, depletion, and amortization(9,515,967) (9,344,212)(11,372,217) (9,344,212)
Unproved properties not subject to amortization—
 —
Oil and natural gas properties, net$37,651,450
 $37,822,070
$40,349,940
 $37,822,070
Other property and equipment 
  
 
  
Furniture, fixtures and office equipment, at cost$348,507
 $343,178
$288,732
 $343,178
Artificial lift technology equipment, at cost497,606
 377,943
330,525
 377,943
Less: Accumulated depreciation(401,171) (296,294)(310,846) (296,294)
Other property and equipment, net$444,942
 $424,827
$308,411
 $424,827
 
During the quarternine months ended September 30, 2014,ended March 31, 2015, we incurred $119,663225,883 of costs related to the installation of our artificial lift technology, GARP®,on the remaining two wells of a five-well program for a third-party customer. Under the contract for these installations, we fund the majority of the
incremental equipment and installation costs and will receive 25% of the net profits from production, as defined, for as long as
the technology remains in the wells. We are depreciating these costs using a method and a life which approximates the relative timing and amounts of our expected net revenues from the wells. During the quarternine months ended September 30, 2014,March 31, 2015, we recorded additional depreciation of $273,301 reflecting the impairment of unrecovered installation costs of artificial lift equipment, net of estimated residual salvage value, which had been removed from three wells of a third-party customer. Artificial lift equipment cost and corresponding accumulated depreciation have both been reduced by the $273,301 impairment.

67
tableTable of contentsContents
Evolution Petroleum Corporation And Consolidated Subsidiaries
 Notes to Unaudited Consolidated Condensed Financial Statements


additional depreciation
Note 5—Other Assets

As of $76,515 to expenseMarch 31, 2015 and June 30, 2014 our other assets consisted of the unrecovered installation costs of artificial lift equipment which was removed from one well and reinstalled in another well of a third-party customer.following:

 March 31,
2015		 June 30,
2014
Trademarks$43,333
 $40,928
Patent costs487,064
 305,592
Less: Accumulated amortization of patent costs(39,992) (27,050)
Deferred loan costs306,740
 243,003
Less: Accumulated amortization of deferred loan costs(134,898) (98,421)
Other assets, net$662,247
 $464,052


Note 36 — Accrued Liabilities and Other
 
As of September 30, 2014March 31, 2015 and June 30, 2014 our other current liabilities consisted of the following:
September 30,
2014		 June 30,
2014		March 31,
2015		 June 30,
2014
Accrued incentive and other compensation$323,318
 $1,358,653
$566,465
 $1,358,653
Accrued restructuring charges175,307
 530,412
—
 530,412
Officer retirement costs116,289
 288,258
—
 288,258
Asset retirement obligations due within one year10,219
 146,703
10,219
 146,703
Accrued royalties77,376
 89,179
69,344
 89,179
Accrued franchise taxes113,027
 87,575
94,473
 87,575
Other accrued liabilities58,477
 57,224
49,191
 57,224
Accrued liabilities and other$874,013
 $2,558,004
$789,692
 $2,558,004
 
Note 47 — Restructuring
 
On November 1, 2013, we undertook an initiative to refocus our business to GARP®GARP® development that resulted in an
adjustment of our workforce with less emphasis on oil and gas operations and greater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of approximately $1,332,186 representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of severance compensation and benefits to be paid during the twelve months ended December 31, 2014.  Our current estimateAll of the remainingCompany's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges as of September 30, 2014 is as follows:

Type of Cost
Balance at
December 31,
2013
 Payments Adjustment to Cost September 30, 2014
Balance at
December 31,
2013
 Payments Adjustment to Cost Balance at
December 31,
2014
Salary continuation liability$615,721
 $(461,790) $—
 $153,931
$615,721
 $(615,721) $—
 $—
Incentive compensation costs185,525
 (185,525) —
 —
185,525
 (185,525) —
 —
Other benefit costs and employer taxes154,575
 (94,199) (39,000) 21,376
154,575
 (110,144) (44,431) —
Accrued restructuring charges$955,821
 $(741,514) $(39,000) $175,307
$955,821
 $(911,390) $(44,431) $—



8
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 58 — 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 threenine months ended September 30, 2014,March 31, 2015, and for the year ended June 30, 2014:
September 30,
2014		 June 30,
2014		Nine Months Ended 
 March 31, 2015		 Year Ended
June 30,
2014
Asset retirement obligations — beginning of period$352,215
 $615,551
$352,215
 $615,551
Liabilities sold—
 (48,273)(52,526) (48,273)
Liabilities incurred(a)—
 —
564,019
 —
Liabilities settled(137,604) (323,665)(137,604) (323,665)
Accretion of discount4,636
 41,626
23,697
 41,626
Revision of previous estimates—
 66,976
9,670
 66,976
Less obligations due within one year(10,219) (146,703)(10,219) (146,703)
Asset retirement obligations — end of period$209,028
 $205,512
$749,252
 $205,512
 

7
table(a) Liabilities incurred during the period relate to our share of contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notesthe the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to Unaudited Consolidated Condensed Financial Statementsthe reversion of our working interest.


Note 6—9— Stockholders’ Equity

 Common Stock
 
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.share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. During the threenine months ended September 30, 2014, weMarch 31, 2015, the Company declared three quarterly dividends and paid $3,279,341 of dividends$8,192,989 to ourits common shareholders. stockholders. 


For the quarternine months ended September 30, 2014,March 31, 2015, the Board of Directors authorized the issuance of 144,468 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award. In addition, the Board authorized the issuance of 43,258 shares of restricted common stock to various employees for incentive compensation purposes.purposes and issued 25,740 shares of restricted common stock as compensation to the Company's directors. See Note 710 - Stock-Based Incentive Plan.

 Series A Cumulative Perpetual Preferred Stock
 
At September 30, 2014,March 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. Optional redemption can only be made by us on or after July 1, 2014 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 shareholders,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 $168,575$505,726 and $168,575$505,726 to holders of our Series A Preferred Stock during the threenine months ended September 30,March 31, 2015 and 2014, and 2013, respectively.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2014, cash dividends on preferred and common stock were treated for tax purposes as a return of capital to our shareholders.stockholders. Based on our current projections we expect that the majority, if not all, of our cash dividends for the fiscal year ending June 30, 2015, we expect preferred dividends will be treated as qualified dividend income and notthat a portion of our cash dividends on common stock will be treated as a return of capital.capital and the remainder as qualified dividend income. We will make a finalpreliminary determination regardingregar

9
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


ding the tax treatment of dividends for the current fiscal year when we report this information to recipients. As a result of the difference between our June 30 fiscal year and the calendar year basis of our dividend reporting requirements, it is possible that we will be required to amend these reports when our final taxable income for the fiscal year is determined, as this will potentially affect the tax status of our dividends. 

Note 7—10— Stock-Based Incentive Plan
 
We may grant option awards to purchase common stock (the "Stock Options"), restricted common stock awards
(" ("Restricted Stock"), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company
under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"). The Plan authorizes the
issuance of 6,500,000 shares of common stock and 568,269542,529 shares remain available for grant as of September 30, 2014.March 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 September 30, 2014,March 31, 2015, and the changes during the fiscal year:
 
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, 2014178,061
 $2.08
  
  
Stock Options outstanding at September 30, 2014178,061
 $2.08
 $1,264,907
 1.5
Vested or expected to vest at September 30, 2014178,061
 $2.08
 $1,264,907
 1.5
Exercisable at September 30, 2014178,061
 $2.08
 $1,264,907
 1.5
 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, 2014178,061
 $2.08
  
  
Exercised(87,000) 1.63
  
  
   Stock Options outstanding at March 31, 201591,061
 2.50
 $313,720
 1.6
   Vested or expected to vest at March 31, 201591,061
 2.50
 313,720
 1.6
Exercisable at March 31, 201591,061
 $2.50
 $313,720
 1.6

8
table of contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements



(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($9.185.95 as of September 30, 2014)March 31, 2015) and the Stock Option exercise price of in-the-money Stock Options.

Restricted Stock and Contingent Restricted Stock

Prior to the quarter ended September 30,August 28, 2014 all restricted stock grants contained a four-year vesting period based solely on service. Restricted stockStock which vests based solely on service is valued at the fair market value on the date of grant and amortized over the service period.

During the threenine months ended September 30, 2014,March 31, 2015, the Company awarded long-term incentive grants of both restricted stockRestricted Stock and contingent restricted stock.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 stockRestricted Stock grants were issued on the date of grant, whereas the contingent restricted stockRestricted 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 upon vesting. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period 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 remainder of the fourfour- year term. As of September 30, 2014,March 31, 2015, the Company does not consider the vesting of these performance-based grants to be probable and no compensation expense has been recognized.

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

10
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


period of these awards waswere 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. Fair values for these market-based awards ranged from $4.26 to $8.40 with expected vesting periods of 3.30 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.

The following table sets forth the Restricted Stock transactions for the threenine months ended September 30, 2014:March 31, 2015:
 
Number of
Restricted
Shares
 
Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at September 30, 2014 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014140,067
 $8.70
    
Service-based shares granted75,170
 10.13
    
Performance-based shares granted76,642
 10.05
    
Market-based shares granted35,914
 7.59
    
Vested(21,873) 6.86
    
Unvested at September 30, 2014305,920
 $9.39
 $1,789,833
 2.9
 Number of
Restricted
Shares		 Weighted
Average
Grant-Date
Fair Value		 Unamortized Compensation Expense at March 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014140,067
 $8.70
    
Service-based awards granted100,910
 9.53
    
Performance-based awards granted76,642
 10.05
    
Market-based awards granted35,914
 7.59
    
Vested(77,920) 8.48
    
Forfeited—
 —
    
Unvested at March 31, 2015275,613
 $9.30
 $1,528,996
 2.5

(1) Excludes $770,252 of potential future compensation expense for performance-based awards that arefor which vesting is not probable.considered probable at this time for accounting purposes.


9
table of contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


The following table summarizes Contingentcontingent Restricted Stock activity:
Number of
Restricted
Stock Units		 Weighted
Average
Grant-Date
Fair Value		 Unamortized Compensation Expense at September 30, 2014 (1) Weighted Average Remaining Amortization Period (Years)Number of
Restricted
Stock Units		 Weighted
Average
Grant-Date
Fair Value		 Unamortized Compensation Expense at March 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014—
 $—
   —
 —
   
Performance-based awards granted38,325
 10.05
   38,325
 $10.05
   
Market-based awards granted17,961
 4.26
   17,961
 4.26
   
Unvested at September 30, 201456,286
 $8.20
 $74,502
 3.2
Unvested at March 31, 201556,286
 $8.20
 $62,787
 2.7
 
(1) Excludes $385,166 of potential future compensation expense for performance-based awards that arefor which vesting is not probable.considered probable at this time for accounting purposes.

Stock-based compensation expense related to Restricted Stock and Contingentcontingent Restricted Stock grants for the three months ended September 30,March 31, 2015 and 2014 was $242,835 and 2013$444,981, respectively. Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the nine months ended March 31, 2015 and 2014 was $243,337$731,192 and $373,438,$1,134,841, respectively. For the nine months ended March 31, 2015, this expense includes $15,328 for cash dividends paid on unvested, "not probable" performance-based awards which are not being amortized to expense. Recipients are not required to return dividend payments to the Company if the awarded Restricted Stock never vests. See Note 7 – Restructuring, for stock compensation included in Restructuring Charges recorded at December 31, 2014.

Note 811 — 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:

11
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements



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 Financial Instruments.  The Company’s other financial instruments consist of cash and cash equivalents, certificates of deposit, receivables and payables. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.

Other Fair Value Measurements.  The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values, which we review quarterly.

Note 912 — 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.
 
There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the threenine months ended September 30, 2014.March 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, 2010 through June 30, 2014.
 

10
table of contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Our effective tax rate for any period may differ from the statutory federal rate due to (i) our state income tax liability in Louisiana; (ii) stock-based compensation expense related to qualified incentive stock option awards (“ISO awards”), which creates a permanent tax difference for financial reporting, as these types of awards, if certain conditions are met, are not deductible for federal tax purposes; and (iii) statutory percentage depletion, which may create a permanent tax difference for financial reporting.

Based on the carryback of tax losses resulting from the exercise of stock options and incentive warrants in fiscal 2014, we filed a request for refund of cash taxes paid in Louisiana for the previous three fiscal years totaling approximately $1.5 million. This refund request is subject to final approval by the Louisiana tax authorities and we cannot be certain of the timing or amount of the ultimate recovery. This carryback will utilize approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes, with $5.1 million of tax loss carryforwards remaining for Louisiana tax purposes. When received, this refund will not affect our tax provision for financial reporting purposes. We will recognize the benefit as an increase in additional paid-in capital.
 
We recognized income tax expense of $706,159$2,118,218 and $482,636$1,148,155 for the threenine months ended September 30,March 31, 2015 and 2014, and 2013, respectively, with corresponding effective rates of 38.5%40.6% and 24.7%36.6%.
 

12
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 1013 — Net Income Per Share
 
The following table sets forth the computation of basic and diluted income (loss) per share:
 Three Months Ended September 30,Three Months Ended March 31, Nine Months Ended March 31,
 2014 20132015 2014 2015 2014
Numerator  
  
 
  
  
  
Net income available to common shareholders $960,435
 $1,303,876
$566,011
 $755,125
 $2,597,788
 $1,481,542
Denominator  
  
 
  
  
  
Weighted average number of common shares — Basic 32,682,401
 28,607,320
32,861,001
 32,358,163
 32,789,157
 30,328,344
Effect of dilutive securities:  
  
 
  
  
  
Weighted average of contingent restricted stock grants 1,552
 —
Weighted average of stock options 142,297
 3,603,945
Contingent restricted stock grants5,954
 —
 3,568
 —
Stock options91,263
 373,886
 117,256
 2,175,116
Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,826,250
 32,211,265
32,958,218
 32,732,049
 32,909,981
 32,503,460
           
Net income per common share — Basic $0.03
 $0.05
$0.02
 $0.02
 $0.08
 $0.05
Net income per common share — Diluted $0.03
 $0.04
$0.02
 $0.02
 $0.08
 $0.05
 
Outstanding potentially dilutive securities as of September 30, 2014March 31, 2015 were as follows:
Outstanding Potential Dilutive Securities
Weighted
Average
Exercise Price
 
At
September 30,
2014
Contingent restricted stock grants$—
 56,286
Stock options$2.08
 178,061
 $1.58
 234,347
Outstanding Potential Dilutive SecuritiesWeighted
Average
Exercise Price		 At March 31, 2015
Contingent Restricted Stock grants—
 56,286
Stock Options$2.50
 91,061
 $1.55
 147,347
 
Outstanding potentially dilutive securities as of September 30, 2013March 31, 2014 were as follows:
Outstanding Potential Dilutive Securities
Weighted
Average
Exercise Price
 At
September 30,
2013		Weighted
Average
Exercise Price		 At March 31, 2014
Stock options$1.99
 4,822,820
$2.02
 228,061
 
Note 11 -14 — Unsecured Revolving Credit Agreement
 
On February 29, 2012, Evolution Petroleum CorporationEPM entered into a Credit Agreementcredit agreement (the “Credit Agreement”) with Texas Capital Bank, N.A. (the “Lender”).  The Credit Agreement provides us 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.years, expiring on February 29, 2016.  Our subsidiaries guaranteed the Company’sguarantee EPM’s obligations under the facility.  We may use the proceeds of any loans under the facility 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.
 

11
table of contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Semi-annually, the borrowing base and a monthly reduction amount are re-determined from our 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.defined in the Credit Agreement.
 
At our 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% and 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

13
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


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 reflecting 3.5% per annum rate applied to their principal amounts 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.  We are 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 we 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 that 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 Series A 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 all amounts outstanding under the Credit Agreement, if any, to be immediately due and payable.
 
As of September 30, 2014,March 31, 2015, 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 May 2014, the Credit Agreement was amended to permit the payment of cash dividends on common stock if no borrowings are outstanding at the time of such payment.
 
In connection with this agreement we incurred $179,468 of debt issuance costs, which 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
issuance costs related to the Credit Agreement was $68,888$44,570 as of September 30, 2014.March 31, 2015. The Company is in discussions with the
Lender to replace the unsecured Credit Agreement with an expanded secured facility. As of September 30, 2014,March 31, 2015, the Company had incurred approximately $88,251$127,272 in legal and title costs related to this proposed agreement, which are also capitalized in Other Assets.

Note 1215 — 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.  For

The Company and its wholly-owned subsidiary NGS Sub Corp. are defendants in a lawsuit brought by John C. McCarthy et al in the fifth District Court of Richland Parish, Louisiana in July 2011. The plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006. The plaintiffs are seeking cancellation of the transaction and monetary damages. On March 29, 2012, the Fifth District Court dismissed the case against the Company and NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiffs’ claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. We subsequently filed a second motion pleading “no cause of action,” with which the district court again agreed and dismissed the plaintiffs’ case on September 23, 2013. Plaintiffs again filed an appeal in November 2013. In October 2014, the appellate court reversed the district court. We subsequently filed for a rehearing which was denied. We now have filed an Application for Writ of Review in the Louisiana Supreme Court in which we have asked the Louisiana Supreme Court to reverse the appellate court and reinstate the trial court judgment dismissing plaintiffs’ case. Amicus Curiae Briefs have been filed in support of the writ application by the Louisiana Oil & Gas Association, the Louisiana Mid-Continent Oil and Gas Association and the American Association of Professional Landmen. The Application for Writ of Review was unanimously accepted by the Louisiana Supreme Court, our brief and supporting Amicus Curiae Briefs have been filed and oral arguments are expected to be scheduled in the near term.

14
Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements



As previously reported, on August 23, 2012, we and our wholly-owned subsidiary, NGS Sub Corp., and Robert S. Herlin, our Chief Executive Officer, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones (the “Jones lawsuit”) in the Western District Court of the Monroe Division, Louisiana. The plaintiffs alleged primarily that we (defendants) wrongfully purchased the plaintiffs’ 4.8119% overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for enhanced oil recovery. The plaintiffs were seeking rescission of the assignment of the overriding royalty interest and monetary damages. We believed that the claims were without merit and not timely, and we vigorously defended against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the plaintiffs to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the plaintiffs' claims were valid on their face. On September 25, 2013, plaintiff Jones filed a motion to alter or amend the September 17, 2013 judgment. On December 27, 2013, the court denied said plaintiffs’ motion, and on January 21, 2014, we filed a motion to reconsider the nondismissal of the remaining claims, which was denied. The Court entered a Scheduling Order setting trial of the case for the week of June 15, 2015. Subsequent to depositions of the plaintiffs, in late March 2015, in the United States District Court for the Western District of Louisiana Monroe Division, a joint motion to dismiss with prejudice was entered into by all parties in the lawsuit and the judge signed the judgment of dismissal with prejudice. Further, no compensation or other consideration was paid or provided to the plaintiffs by any of the defendants other than an agreement by us not to sue for malicious prosecution or defamation, or seek sanctions, and the plaintiffs agreed to relinquish any and all claims to the 4.8119% overriding royalty interest in the Delhi Unit.

On December 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd 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. We subsequently amended and expanded our claims. The Company disagrees with, and is vigorously defending against, Denbury's counterclaims.

On January 26, 2015, Denbury notified us it had withheld and suspended 2.891545% of our overriding royalty revenue interest in the field for the months of November and December 2014. This unilateral suspension of a portion of our overriding royalties by the operator was made without consultation with the Company and, we believe, was without legal proceedings, see “Part II, Item 1. Legal Proceedings.”basis. On February 26, 2015, we and Denbury executed an agreement under which Denbury agreed to reverse the previously disclosed suspension of our overriding royalty interest revenues and release to Evolution amounts previously suspended totaling approximately $712,000.  Denbury further agreed not to suspend any future revenues attributable to any of our revenue interests, except under limited circumstances. This agreement did not settle any of the outstanding litigation matters with Denbury, including their counterclaim related to the net revenue interest conveyed in the 2006 Purchase and Sale Agreement.

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 Mr. Brooks' claims against NGS Sub Corp. We have denied and are vigorously defending all claims by Mr. Hawkins and do not consider the claims material to the Company.

 

1215
tableTable of contentsContents
Evolution Petroleum Corporation And Consolidated Subsidiaries
 Notes to Unaudited Consolidated Condensed Financial Statements


Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of September 30, 2014March 31, 2015 under this operating lease are as follows: 
For the twelve months ended September 30, 
2015$159,011
For the twelve months ended March 31, 
2016132,509
$159,011
201753,004
Total$291,520
$212,015
 
Rent expense for the three months ended September 30,March 31, 2015 and 2014 and 2013 was $43,776 and $41,918,$44,473, respectively. Rent expense for the nine months ended March 31, 2015 and 2014 was $131,327 and $131,151, respectively.
 
Employment Contracts.  We have entered into employment agreements with two of the Company's senior executives.
The employment contracts provide for severance payments in the event of termination by the Company for any reason other
than cause or permanent disability, or in the event of a constructive termination, as defined. The agreements provide for the
payment of base pay and certain medical and disability benefits for periods ranging from six months to one year after termination.  The total contingent obligation under the employment contracts as of September 30, 2014March 31, 2015 is approximately $473,000.
Note 13 — Subsequent Events

On October 24, 2014, the Company sold all of its joint venture interests in its Mississippian Lime properties in Kay County, Oklahoma for approximately $400,000, net of customary closing adjustments, and the buyer's assumption of all abandonment liabilities.

Denbury Resources, Inc., operator of the Delhi Field in northeast Louisiana, has informed the Company of its preliminary determination that payout occurred during the month of October 2014 and that the Company will earn its reversionary working interest of 23.9% and associated revenue interest of 19.1% in the Delhi Field effective November 1, 2014. When combined with our existing 7.4% royalty and overriding royalty interests, our total net revenue interest will increase to 26.5%, while we will now be responsible for paying 23.9% of the operating costs and capital expenditures going forward.


1316
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, 2014 (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 2014 Annual Report on Form 10-K for the year ended June 30, 2014 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 incremental oil and gas reserves within known oil and gas resources for our shareholdersstockholders 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 shareholders,stockholders, and a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership ofin our common stock.

Our strategy is to grow the value of our Delhi asset to maximize the value realized by our shareholdersstockholders while commercializing our patented GARP®GARP® artificial lift technology for recovering incremental oil and gas reserves in mature fields.

We expect to fundare currently funding our fiscal 2015 capital program from working capital and net cash flows from our properties.
 
Highlights for our FirstThird Quarter of Fiscal 2015 and Project Update

“Q1-15”"Q3-15" & “current quarter” is"current quarter" refer to the three months ended September 30, 2014,March 31, 2015, the company’s 1stCompany's 3rd quarter of fiscal 2015.

“Q4-14”"Q2-15" & “prior quarter” is"prior quarter" refer to the three months ended June 30,December 31, 2014, the company’s 4thCompany's 2nd quarter of fiscal 2014.2015.

“Q1-14”"Q3-14" & “year-ago quarter” is"year-ago quarter" refer to the three months ended September 30, 2013,March 31, 2014, the company’s 1stCompany's 3rd quarter of fiscal 2014.
 
Operations

·
For Q1-15, weQ3-15, the Company earned $1.0$0.6 million of net income, or $0.03$0.02 per diluted common share, a 26%25% decrease from the year-ago quarter and a 33% decline47% decrease from the previousprior quarter.The significant decline in oil prices is the primary driver for lower net income compared to both the year-ago quarter and the prior quarter, despite increased sales volumes as a result of our reversionary working interest at Delhi.

·
Current quarter revenues were $4.0$7.1 million, a 14% decrease63% increase from the year-ago quarter and a 7% declinean 8% decrease from the previousprior quarter.The increase from the year-ago quarter was due to net revenues associated with the reversion

1417
Table of Contents

of our working interest ownership in the Delhi field in November 2014, offset by significantly lower realized oil prices due to current market conditions. The decrease from prior quarter is due to lower realized oil prices under current market conditions, offset by increased oil volumes at Delhi for three months versus only two months of working interest sales based on the November 1, 2014 effective date of our reversionary working interest.

·Our Delhi production averaged 4251,640 net barrels of oil per day (“BOPD”) (5,739 BOPD gross), a 3% decrease from both the previous quarter and the year-ago quarter. Realized price per barrel declined 4.6% from the previous quarter and 10%259% increase from the year-ago quarter, and a 38% increase from the prior quarter. The increase in volumes from the year-ago quarter is due to $98.96the additional volumes associated with the working interest ownership in the Delhi field. The increase in volumes from prior quarter is due to three months of working interest production versus two months, post payout effective as of November 1, 2014. Gross production in the field averaged 6,203 BOPD during the current quarter, an increase of 5% over the prior quarter gross rate of 5,892 BOPD.

Delhi average realized crude oil prices received in Q3-15 decreased 53% to approximately $48 per barrel.barrel from approximately $102 per barrel in the year-ago quarter, and decreased 32% from approximately $70 per barrel in the prior quarter.
·Delhi oil pricing is based on Louisiana Light Sweet index, which continues to be valued at a premium compared to West Texas Intermediate.

We remain debt-free while distributing $3.3and distributed $1.6 million of cash dividends to our common shareholders instockholders during the form of cash dividends.current quarter.
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, 2014.
Delhi Field EOR—Northeast Louisiana- Enhanced Oil Recovery Project

Gross production at Delhi in the firstthird quarter of fiscal 2015 was 5,739averaged 6,203 BOPD, down 3%a increase of 1% from the fourthyear-ago quarter, and a 5% increase from the prior quarter. Net production averaged 1,640 BOPD, a 259% increase from the year-ago quarter, and a 38% increase from the prior quarter. Gross production continues to be positively impacted by a replacement well that was redrilled and placed into production in January 2015.

In the quarter ending March 31, 2015, our net share of the last fiscal yearjoint interest billed lease operating expenses was approximately $2.9 million, of which $1.6 million is related to CO2 purchases and down 3% from the year ago quarter. As previously disclosed,transportation expenses. Under our contract with the operator, has deferred capital spendingpurchased CO2 is priced at 1% of the oil price in the field since early 2013 pending reversionper thousand cubic feet (“Mcf”) plus transportation costs of our$0.20 per Mcf. Total average CO2 costs per month are down 36% from the prior quarter monthly as result of both lower oil prices and lower purchased CO2 volumes in the quarter. Purchased CO2 volumes in the prior quarter were significantly higher than the expected rates going forward of 90,000 to 95,000 Mcf per day. On a total BOE basis, average CO2 costs were down 29% from $15.33 BOE in the prior quarter to $10.82 BOE, primarily due to increased working interest volumes and has also chosenlower realized oil prices in the current quarter. Our purchased CO2 costs are directly correlated with realized oil prices.

In late February 2015, we signed an authorization for expenditure for construction of a natural gas liquids ("NGL") recovery plant in the Delhi field, which will extract both NGL and methane from the field. In addition to operatethe value of these hydrocarbon products, according to the operator, the increased purity of the CO2 stream re-injected into the field at a slightly lower reservoir pressure, which lowersshould result in significant operational benefits to the rateCO2 flood and potentially increase oil production from existing wells and/or accelerated recovery of oil production without reducing miscibility or lowering ultimate reserves.
We have been informed The NGL plant has an estimated gross cost of $103 million ($24.6 million net to the Company) projected to be expended through the summer of 2016.  Recovered methane will be utilized to generate much, if not all, of the electricity for the operation of the gas plant and other CO2 field operations.  This will substantially reduce operating costs for both the existing field operation and the new plant operating costs. The plant is projected by the operator to produce up to approximately 2,000 barrels of its preliminary determination that payout occurred during the monthNGL's per day when in full operation and NGL volumes potentially may be higher based on performance and yield. 

On January 26, 2015, Denbury notified us it had withheld and suspended 2.891545% of October 2014 and the Company will earn its approximate reversionary workingour overriding royalty revenue interest of 23.9% (with related 19.1% net revenue interest) in the Delhi Field effective November 1, 2014. With this reversion, we and the operator have plans to resume expansion of the CO2 flood to the east and begin construction of a recycle gas processing plant in the field for the months of November and December 2014, as previously disclosed. This unilateral suspension of a portion of our overriding royalties by the operator was made without consultation with the Company and, we believe, was without legal basis. On February 26, 2015, we entered into an agreement under which Denbury agreed to recover methanereverse the previously disclosed suspension of our overriding royalty interest revenues and natural gas liquids while makingrelease to Evolution amounts previously suspended totaling approximately $712,000.  Denbury further agreed not to suspend any future revenues attributable to any of our revenue interests, except under very limited circumstances. This agreement does not settle any of the flood more efficient. We believe that these actions bode well for future increasesoutstanding litigation

18
Table of Contents

matters with Denbury, including their counterclaim related to the net revenue interest conveyed in production rates from the field.2006 Purchase and Sale Agreement.
GARP®
GARP® - Artificial Lift Technology

During the current quarter, we completed the GARP® installation in the Appelt #1H well, that had been shut-in for over a year due to solids production, was worked over to install better solids handling capacity and thereby restored to producing status at the previous rate of GARP®approximately 10 barrels of oil per day. The Selected Lands #2 well was also restored to production in onethe quarter. Lastly, the Philip #1 well was temporarily abandoned after unsuccessful workovers to permanently remove solids from sticking to the pump. These workovers were included in our operating costs for a third party operator and started the installation of a second well. The secondquarter.
We continue to work diligently to advance the development of the two installations wasGARP® technology and expect to file three GARP® patents and one provisional GARP® patent in progress at the end of the quarter. We removed the tangible equipment from a previous installation for this customer in which wellbore obstructions limited production,coming weeks to solve specific needs identified by customers.
Recent GARP® marketing and utilized it on the first of these two wells. Webusiness development efforts have seen a positive response from the first two productive GARP® wells under this agreement completed during the previous quarter, although high operating costssecured three master service agreements, including with one major, one super-independent and one large independent oil producer and a low net-back from gas processing under the customer’s pre-existing gas sales contract in the first few months have limited the revenues from our net profits interest.fourth agreement is pending.
Artificial lift financial results were adversely affectedApproval as a vendor to provide oil field services does not guarantee an agreement to install GARP® technology, which is governed by major workover operations on two of our three Company-operated wells, which temporarily suspended production during portions of the quarter and substantially reduced GARP® revenues.a separate agreement.    
Other Properties
Subsequent to the end of the quarter, we closed on the sale of all of our remaining interests in the Mississippian Lime project for cash proceeds of approximately $400,000, subject to customary closing adjustments. This transaction completes the process of divesting of all of our non-core oil and gas properties which we commenced in 2013.
Liquidity and Capital Resources
 
At SeptemberWe had $20.4 million and $23.9 million in cash and cash equivalents at March 31, 2015 and June 30, 2014, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility at period end.

During the nine months ended March 31, 2015, we financed our operations with cash generated from operations and cash on hand. At March 31, 2015, our working capital was $21.9$18.4 million, compared to working capital of $23.3 million at June 30, 2014.  The major factors which resulted$4.9 million working capital decrease is primarily due to a $4.1 million increase in the $1.4accounts payable reflecting post-reversion Delhi field operating expenses and capital expenditures together with $3.5 million decrease were the payment of $1.5lower cash, partially offset by $1.6 million in annualof lower accrued liabilities principally attributable to incentive compensation, in September 2014 that reduced our net cash flow from operationsrestructuring and the payment of $3.3officer retirement accrual declines and $1.0 million of common stock dividends inincreased accounts receivable primarily due to the current quarter.interest reversion.
 
Cash Flows from Operating Activities
 
For the threenine months ended September 30,March 31, 2015, cash flows provided by operating activities were $6.6 million, which included $0.4 million used by other working capital items.  Of the $7.0 million provided before other working capital changes, approximately $3.1 million was due to net income, and approximately $3.9 million was attributable to non-cash expenses and settlements of asset retirement obligations.
For the nine months ended March 31, 2014, cash flows provided by operating activities were $0.6$5.7 million, reflecting $1.6$5.4 million provided by operations before $1.0$0.2 million usedprovided by other working capital changes, primarily for the payment of annual incentive compensation.changes. Of the $1.6$5.4 million provided before other working capital changes, $1.1$2.0 million was due to net income, which includes $1.3 million of restructuring and $0.5$0.6 million of retirement obligation charges, and $3.4 million was attributable to non-cash expenses.

15
Table of Contents

For the three months ended September 30, 2013, cash flows provided by operating activities were $1.6 million, reflecting $2.3 million provided by operations before $0.7 million was used in working capital. Of the $2.3 million provided before working capital changes, $1.5 million was due to net income and $0.8 million was due primarily to non-cash expenses.
 
Cash Flows from Investing Activities
 
Investing activities for the threenine months ended September 30, 2014March 31, 2015 used $213,000$2.5 million of cash, consisting primarily of $151,000capital expenditures of approximately $2.4 million for Delhi field, $0.3 million for artificial lift technology capital equipment and $55,000together with $0.2 million of other assets comprised primarily of GARP® patent costs, partially offset by $0.4 million of proceeds received for GARP® patent costs.the sale of properties in the Mississippi Lime project in October 2014.
 
Cash paid for oil and gas capital expenditures during the threenine months ended September 30, 2013March 31, 2014 was $594,000.$1.0 million. Development activities were predominantly for GARP® installationsabout equally divided among GARP® wells in Giddings and additional testing in the Sneath and Hendrickson wellwells completed in the Mississippi Lime.Lime during the prior year. We received approximately $67,000$542,000 of additional proceeds related tofrom asset sales, including $400,000 from the June 2013 sale of certainour South Texas properties, and $250,000 of our Giddings Field properties.cash from the maturity of a certificate of deposit.


19
Table of Contents

Cash Flows from Financing Activities
 
In the threenine months ended September 30, 2014,March 31, 2015, we used $3.0$7.6 million in cash for financing activities principally consisting of cash outflows of $3.3$8.2 million for common stock dividend payments and $169,000$0.5 million for preferred dividend payments, offset partially by $537,000$1.1 million of cash provided by tax benefits related to stock-based compensation.

In the threenine months ended September 30, 2013,March 31, 2014, we paidused $5.3 million in cash for financing activities, including cash inflows of $3.2 million from stock option exercise proceeds and $0.1 million of windfall tax benefits, offset by cash outflows of $6.5 million for common dividends, $0.5 million for preferred dividends of $169,000 and purchased $117,000 of treasury$1.6 million for stock through theexchanged for payroll tax liabilities and exercise price payments related to incentive stock surrender of certain employees in satisfaction of payroll liabilities for contemporaneouswarrant and stock option exercises and restricted stock vesting. vestings.

Capital Budget
Delhi Field
With the operator's determination that reversion of our 23.9% working interest and 19.1%19.036% net revenue interest in Delhi occurred effective November 1, 2014, we will beginbegan funding our share of capital and operating expenditures in the Field.field as of that date going forward. From reversion through March 31, 2015, our net share of the joint interest billed capital expenditures was approximately $4.4 million. Capital expenditures primarily consisted of redrilling a producer well, testing and strengthening of well bore integrity, and drilling and completion of monitoring wells.

               Projected capital expenditures over the next two fiscal years are currently expected to total approximately $25-27$25-35 million net to our working interest. The timing and actual amount of this spending is primarily dependent on the pace of project development by the operator of the Field.and project economics based on current and forward looking oil prices. Of this total, approximately $15-17$24.6 million is for the gas processing plant and approximately $10 millionthe balance is for the roll-out of the next phasecontinued development of the CO2 project.project into the eastern half of the field. We expect these costs to be incurred over portions of the next two fiscal years.years, although these development plans are subject to review and deferral. Total spending based on proved reserves in the reserve report, net to our interest, is currently forecast to be up to approximately $45$50 million over the next four years, which includes the projects above plus further expansion of the CO2 flood patterns. We expect that cash flows from our interests in the Field will be in excess of the net capital expenditures required.
GARP®GARP® - Artificial Lift Technology
Based on our current marketing and business plans, we expect that our capital requirements for artificial lift technology operations will be relatively modestminor over the next fiscal year.
Liquidity Outlook
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. To date, our Board of Directors have followed a policy of not hedging future commodity sales due to our having no outstanding debt. As a result, our future revenues, cash flow, profitability, access to capital and future rate of growth is heavily influenced by the prices received for our production. Liquidity could also be affected by any litigation outcome, positive or negative.
Funding for allour anticipated capital expenditures over the next two fiscal years is expected to be met from current working capital and cash flows from operations.operations and current working capital. Our preference is to remain debt free absent any strategic move, but we do have access to a $5 millionan unsecured revolving line of credit and are in discussionshave plans to convert this line tointo a senior secured facility with upsignificantly higher borrowing capacity with an extended term, to $30 million of capacity.use as needed. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs or acquisition opportunities.
Payment of free cash flow in excess of our operating and capital requirements through cash dividends on our common stock remains an important aspecta priority of our financial strategy, and it is our long term goal to maintain or increase our dividends. We expectdividends over time as appropriate. The Board of Directors and management instituted this strategy over a year ago due to our belief that high commodity prices at the excess cash flow fromtime limited attractive oil and gas investment opportunities. However, due to the potential to pursue other opportunities at discounted prices during the current industry downturn combined with the anticipated cost of building and installing the Delhi Field, after reversion of our working interest, will permitrecycle gas processing plant during calendar years 2015 and 2016, the Dividend Committee and the Board of Directors believed it was prudent to begin considering prudent increasesadjust the current dividend rate from $0.40 per share annually to $0.20 per share annually, effective in the level of ourquarter ending March 31, 2015. The reduction in the dividend payout during Fiscal 2016.rate will allow the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield.

1620
Table of Contents

Results of Operations
 
Three month periods ended September 30,March 31, 2015 and 2014 and 2013
 
The following table sets forth certain financial information with respect to our oil and natural gas operations:
Three Months Ended September 30,    Three Months Ended March 31,    
2014 2013 Variance Variance %2015 2014 Variance Variance %
Delhi field:              
Crude oil revenues$3,868,602
 $4,429,811
 $(561,209) (12.7)%$7,039,868
 $4,185,156
 $2,854,712
 68.2 %
Crude oil volumes (Bbl)39,094
 40,279
 (1,185) (2.9)%147,621
 41,137
 106,484
 258.9 %
Average price per Bbl$98.96
 $109.98
 $(11.02) (10.0)%$47.69
 $101.74
 $(54.05) (53.1)%
              
Delhi field production costs$2,932,946
 $—
 $2,932,946
 — %
Delhi field production costs per BOE$19.87
 $—
 $19.87
 — %
       
Artificial lift technology:              
Crude oil revenues$74,980
 $101,873
 $(26,893) (26.4)%$12,695
 $95,031
 $(82,336) (86.6)%
NGL revenues22,227
 23,196
 (969) (4.2)%1,352
 29,360
 (28,008) (95.4)%
Natural gas revenues15,552
 17,022
 (1,470) (8.6)%529
 26,661
 (26,132) (98.0)%
Service revenue$3,097
 $—
 3,097
  
Service revenues10,245
 —
 10,245
 — %
Total revenues$115,856
 $142,091
 $(26,235) (18.5)%$24,821
 $151,052
 $(126,231) (83.6)%
              
Crude oil volumes (Bbl)772
 946
 (174) (18.4)%285
 966
 (681) (70.5)%
NGL volumes (Bbl)744
 768
 (24) (3.1)%73
 756
 (683) (90.3)%
Natural gas volumes (Mcf)4,439
 5,889
 (1,450) (24.6)%204
 5,453
 (5,249) (96.3)%
Equivalent volumes (BOE)2,256
 2,696
 (440) (16.3)%392
 2,631
 (2,239) (85.1)%
              
Crude oil price per Bbl$97.12 $107.69 $(10.57) (9.8)%$44.54
 $98.38
 $(53.84) (54.7)%
NGL price per Bbl$29.88 $30.20 (0.32) (1.1)%18.52
 38.84
 (20.32) (52.3)%
Natural gas price per Mcf$3.50 $2.89 0.61
 21.1 %$2.59
 4.89
 (2.30) (47.0)%
Equivalent price per BOE$49.98 $52.70 $(2.72) (5.2)%$37.18
 $57.41
 $(20.23) (35.2)%
              
Artificial lift production costs (b)$197,360
 $163,749
 $33,611
 20.5 %
Artificial lift production costs (a)$267,906
 $209,742
 $58,164
 27.7 %
Artificial lift production costs per BOE87.48
 60.74
 $26.74
 44.0 %$683.43
 $79.72
 $603.71
 757.3 %
              
Other properties:              
Revenues$20,369
 $61,797
 $(41,428) (67.0)%$—
 $798
 $(798) (100.0)%
Equivalent volumes (BOE)285
 668
 (383) (57.3)%—
 26
 (26) (100.0)%
Equivalent price per BOE$71.47
 $92.51
 $(21.04) (22.7)%$—
 $30.69
 $(30.69) (100.0)%
              
Production costs$88,022
 $254,501
 $(166,479) (65.4)%$639
 $143,887
 $(143,248) (99.6)%
Production costs per BOE$308.85
 $380.99
 $(72.14) (18.9)%$—
 $5,534.12
 $(5,534.12) (100.0)%
              
Combined:              
Oil and gas DD&A (a)$260,160
 $301,752
 $(41,592) (13.8)%
Oil and gas DD&A (b)$1,099,737
 $302,083
 $797,654
 264.1 %
Oil and gas DD&A per BOE$6.25
 $6.91
 $(0.66) (9.6)%$7.43
 $6.90
 $0.53
 7.7 %

(a) Includes workover costs of approximately $252,000 and $123,000, for the three months ended March 31, 2015 and 2014, respectively, that were primarily utilized to restore production in the Appelt #1H and Selected Lands #2 wells.
(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $109,190$38,765 and $7,921,$9,732, for the three months ended September 30,March 31, 2015 and 2014, and 2013, respectively.
(b) Includes workover costs of approximately $149,000 and $42,000, for the three months ended September 30, 2014 and 2013, respectively. Note: There were three producing wells in the period ending 2014 versus four in the period ending 2013.



1721
Table of Contents

Net Income Available to Common Shareholders.Stockholders.  For the quarterthree months ended September 30, 2014,March 31, 2015, we generated net income to common shareholders of $1.0$0.6 million, or $0.03$0.02 per diluted share, on total revenues of $4.0$7.1 million. This compares to a net income of $.08 million, or $0.02 per diluted share, on total revenues of $4.3 million for the year-ago quarter.  The $0.2 million earnings decrease is primarily due to increased production costs partially offset by higher revenues. The $0.8 million reduction achieved in general and administrative expense was offset by an increase in non-cash DD&A expense. The components of net income are explained in greater detail below.
Delhi Field. Revenues increased 68% to $7.0 million as a result of a 259% increase in production volumes from the year-ago quarter primarily due to our November 1, 2014 reversionary working interest, partially offset by a 53% decline in realized crude oil prices from $101.74 per barrel to $47.69 per barrel. Gross production of 6,203 BOPD was essentially flat compared to the year-ago quarter. Production costs for the current quarter were $2.9 million, of which $1.6 million was for CO2 purchases and transportation expenses, compared to no production costs in the year-ago quarter as those revenues were derived solely from our mineral and overriding royalty interests, which bore no operating expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus $0.20 per Mcf transportation costs. For the current quarter total production costs were $27.60 per working interest BOE, which includes $15.03 per BOE for CO2 purchase costs.

Artificial Lift Technology. Revenues decreased 84% to $25,000 reflecting a 85% volume decrease, primarily as a result of workovers on the Philip DL #1, Appelt #1H and Selected Lands #2 wells, together with a 35% decrease in the realized price per BOE, from $57.41 to $37.18 BOE. In the current quarter, we recorded $10,245 of service fee revenue from the GARP® installations for a third-party customer. These wells have not contributed meaningful net profits to the Company in the current quarter due to low commodity prices, poor netback contracts for gas processing and higher workover costs. Artificial lift production costs were $268,000 for the current quarter, a 28% increase from $210,000 for the year-ago quarter, and includes $252,000 in costs for the aforementioned workovers, which were necessary in recovering proved reserves by restoring significant production in the Appelt and Selected Lands #2 wells.

Other Properties. We have divested all of our non-core oil and gas properties, therefore there are no revenues to report in the current quarter. The prior year-ago quarter had slight revenue of $798. The production costs from the year-ago quarter were high as a result of high water production in our Mississippi Lime property interest which we sold in the prior quarter.

General and Administrative Expenses (“G&A”).  G&A expenses decreased $0.8 million, or 36%, to $1.5 million for the three months ended March 31, 2015 from $2.3 million in the year-ago quarter, primarily due to a $0.6 million decrease in compensation and benefits due to the fiscal 2014 non-recurring charge for the retirement of our vice president and chief financial officer together with $0.3 million decline in accrued incentive compensation, partially offset by $102,000 of higher legal expense, which reflected $0.3 million of current quarter litigation costs.

Depletion & Amortization Expense (“DD&A”).  DD&A increased $827,000, or 265% to $1.1 million for the current quarter compared to $312,000 for the year-ago quarter principally because of higher amortization of our full cost oil and gas property cost pool. Full cost pool amortization increased to $1.1 million from $302,000 in the year-ago quarter due to 238% higher volume of 148,013 BOE as a result of the reversion of our working interest in Delhi field together with a higher rate per BOE ($7.43 in the current quarter versus $6.90 per BOE in the year-ago quarter). Compared to the year-ago quarter, reserves were lower as natural gas proved reserves to be recovered from the recycle stream by the planned Delhi gas plant are now to be used to generate power for the Delhi field and not sold to third party customers. The offset to the lower reserves is a lower projected lease operating expense at Delhi. Additionally, there was some decline in proved reserves at June 30, 2014 from the previous fiscal year-end due to lower injection pressure and development deferrals. Further, our future capital expenditures related to the NGL plant to be constructed over the next fifteen months are higher, offset by a lower operating expense of the plant, due to the working interest owners bearing all of the plant cost instead of the plant contract operator bearing approximately 30% of the plant cost.




22
Table of Contents

Nine month periods ended March 31, 2015 and 2014
The following table sets forth certain financial information with respect to our oil and natural gas operations:
 Nine Months Ended March 31,    
 2015 2014 Variance Variance %
Delhi field:       
Crude oil revenues$18,553,301
 $12,745,203
 $5,808,098
 45.6 %
Crude oil volumes (Bbl)295,915
 124,089
 171,826
 138.5 %
Average price per Bbl$62.70
 $102.71
 $(40.01) (39.0)%
        
  Delhi field production costs$5,750,812
 $—
 $5,750,812
 — %
  Delhi field production costs per BOE$19.43
 $—
 $19.43
 — %
        
Artificial lift technology:       
  Crude oil revenues$129,714
 $340,230
 $(210,516) (61.9)%
  NGL revenues34,607
 77,986
 (43,379) (55.6)%
  Natural gas revenues23,446
 64,821
 (41,375) (63.8)%
  Service revenues16,146
 —
 16,146
 — %
  Total revenues$203,913
 $483,037
 $(279,124) (57.8)%
        
  Crude oil volumes (Bbl)1,620
 3,383
 (1,763) (52.1)%
  NGL volumes (Bbl)1,228
 2,358
 (1,130) (47.9)%
  Natural gas volumes (Mcf)7,056
 17,932
 (10,876) (60.7)%
  Equivalent volumes (BOE)4,024
 8,730
 (4,706) (53.9)%
        
  Crude oil price per Bbl$80.07
 $100.57
 $(20.50) (20.4)%
  NGL price per Bbl28.18
 33.07
 (4.89) (14.8)%
  Natural gas price per Mcf3.32
 3.61
 (0.29) (8.0)%
    Equivalent price per BOE$46.66
 $55.33
 $(8.67) (15.7)%
        
  Artificial lift production costs (a)$656,819
 $526,712
 $130,107
 24.7 %
  Artificial lift production costs per BOE$163.23
 $60.33
 $102.90
 170.6 %
        
Other properties:       
  Revenues$20,369
 $134,754
 $(114,385) (84.9)%
  Equivalent volumes (BOE)285
 1,516
 (1,231) (81.2)%
  Equivalent price per BOE$71.47
 $88.89
 $(17.42) (19.6)%
        
  Production costs$98,051
 $481,697
 $(383,646) (79.6)%
  Production costs per BOE$344.04
 $317.74
 $26.30
 8.3 %
        
Combined:       
Oil and gas DD&A (b)$2,061,440
 $922,781
 $1,138,659
 123.4 %
Oil and gas DD&A per BOE$6.87
 $6.87
 $—
 — %

(a) Includes workover costs of approximately $535,000 and $200,000, for the nine months ended March 31, 2015 and 2014, respectively.
(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $364,169 and $25,875, for the nine months ended March 31, 2015 and 2014, respectively.

23
Table of Contents

Net Income Available to Common Stockholders.  For the nine months ended March 31, 2015, we generated net income to common stockholders of $2.6 million, or $0.08 per diluted share, on total revenues of $18.8 million. This compares to net income of $1.3$1.5 million, or $0.04$0.05 per diluted share, on total revenues of $4.6$13.4 million for the corresponding year-ago quarter.  The earnings decline isperiod.  As higher revenue was mostly offset by increased production costs due to much lower revenueoil prices, the earnings increase is primarily due to expense decreases of $2.3 million for G&A expense and a higher effective income tax rate,$1.3 million for restructuring charges, partially offset by lower general and administrative expenses.$1.5 million of higher DD&A expense. Additional details of the components of net income are explained in greater detail below.
 
Delhi Field. Revenues decreased 13%increased 46% to $3.9$18.6 million as a result of a 3% decline139% increase in production volumes from the year ago quarter andcorresponding year-ago period primarily due to the November 2014 reversion of our working interest, partially offset by a 10%39% decline in realized crude oil prices, from $109.98$102.71 per barrel to $98.96$62.70 per barrel. There areGross production of decreased 3% to 5,942 BOPD compared to 6,116 BOPD for the year-ago period. Production costs for the nine months ended March 31, 2015 were $5.8 million, of which $3.3 million was for CO2 purchases and transportation expenses, compared to no production costs in the Delhi Field,corresponding year-ago period as all currentthose revenues derivewere derived solely from our mineral and overriding royalty interests.interests, which bear no operating expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus $0.20 per Mcf transportation costs. Accordingly, such costs will be reduced in the future if oil prices remain at lower price levels. From our November 1, 2014 working interest reversion to March 31, 2015, total production costs were $32.80 per working interest BOE which includes CO2 costs of $18.66 per working interest BOE.

Artificial Lift Technology. Revenues decreased 19%58% to $116,000$204,000 reflecting a 16%54% volume decrease, primarily as a result of workoversa workover on the Philip DL #1, and Selected Lands #2 wells, together with a 5%16% decrease in the realized price per BOE.BOE, from $55.33 per barrel to $46.66 per barrel. We recorded $3,000$16,146 of service revenue from the recent GARP® initialGARP® installations for a third-party customer. Those twoThese wells did not contribute meaningful net profits to the Company in this quarter, but we believe they will do so in future quarters.the nine months ended March 31, 2015. Artificial lift production costs were $197,000,$657,000, which included $149,000$535,000 in workover costs, for the above workovers, which were successfulnecessary in increasing production.recovering proved reserves by restoring production in two key wells operated by us, the Appelt and the Selected Lands #2.

Other Properties. The Company has beenbegan divesting its non-core oil and gas properties sincein fiscal 2013, and revenues from these properties have correspondingly decreased to $20,000 compared to $62,000$135,000 in the corresponding year-ago quarter.period. The production costs from the prior yearyear-ago period were high as a result primarily fromof workover costs in South Texas and high water production in the MississippianMississippi Lime. WithWe completed our divestiture process in the prior quarter with the sale of the remaining interests in our MississippianMississippi Lime properties subsequent to the end of the quarter, this divestiture process is now completed.properties.

General and Administrative Expenses (“G&A”).  G&A expenses decreased $0.4$2.3 million, or 22%33%, to $1.5$4.6 million during the threenine months ended September 30, 2014March 31, 2015 from $1.9$6.9 million in the corresponding year-ago quarterperiod primarily due to lowerfiscal 2014 non-recurring charges of $0.8 million related to stock option exercises and $0.6 million related to the retirement of our vice president and chief financial officer, a $0.5 million decrease in personnel-related costs as a result of our December 2013 restructuring, and a $0.5 million decline in accrued incentive compensation, partially offset by recent staff additions$0.2 million of higher legal expense, impacted by $0.5 million of fiscal 2015 litigation costs. This fiscal 2014 restructuring charge of $1.3 million consisted of $0.9 million of termination benefits and $0.4 million non-cash charge for GARP®. Salaries and benefits declined $231,000, incentive compensation decreased $60,000 and stock-based compensation expense declined by $130,000.accelerated restricted stock vesting for terminated employees. See Note 7 - Restructuring.

Depletion & Amortization Expense (“DD&A”).  DD&A increased $60,000,$1.5 million, or 19%156%, to $369,000$2.4 million for the current quarter compared to $310,000nine months ended March 31, 2015 from $0.9 million for the corresponding year-ago quarter. DD&Aperiod. Amortization of our full cost oil and gas properties decreasedproperty cost pool increased by $41,000 on lower production and a lower$1.1 million, or 123% primarily due to higher volume generated by the reversionary working interest. For the nine months ended March 31, 2015, our rate of $6.87 per BOE ($6.25 versus $6.91 per BOE inwas flat compared to the corresponding year-ago quarter), while ourperiod. Depreciation expense for other DD&Aproperty and equipment increased by $101,000. This increase primarily includes$338,000 principally due to depreciation of $21,000 related to artificial lift equipment installed in the wells of a third-party customer and a charge of $77,000 to expense the unrecovered installation costs of artificial lift equipment which was removed from one wellplaced in service during fiscal 2015 and reinstalled in another well$273,000 of additional depreciation recognizing the impairment of GARP® equipment installations on three wells of a third-partythird party customer.

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 increaseschanges in costs.  Product prices, operating costs and development costs may not always move in tandem.
 

24
Table of Contents

Known Trends and Uncertainties.  General worldwide economic conditions continue to be uncertain and volatile.  Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas.  We have recently seen significant declines in crude oil prices and are uncertain if this downward price pressure will continue. If such lower crude oil prices persist, our revenues and cash flow going forward will be adversely impacted.  In addition, reversion of our working interest in the Delhi Field will increase both our revenues and lease operating expenses. This will reduce the extraordinary net margins that have resulted from our mineral and overriding royalty interests at Delhi.

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.


18
Table of Contents

Off Balance Sheet Arrangements
 
The Company has no off-balance sheet arrangements to report during the quarter ending September 30, 2014.March 31, 2015.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
 
Information about market risks for the three months ended September 30, 2014,March 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, 2014.
Commodity Price Risk

Our most significant market risk is the pricing for crude oil, natural gas and NGLs. All of such prices have declined significantly during the three months ended March 31, 2015. We expect energy prices to remain volatile and unpredictable. If energy prices decline further 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 dividends, and our ability to borrow and raise additional capital, as, if and when needed. Our general philosophy is not to hedge our commodity price risk. If we chose,choose, we could hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We presently do not hold or issue derivative instruments for hedging or speculative purposes.

Interest Rate Risk
 
We currently have only a small exposure to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.  Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
  
ITEM 4. CONTROLS AND PROCEDURES
 
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.
 
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2014March 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.
 

25
Table of Contents

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended September 30, 2014March 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.
 

19
Table of Contents

PART II - OTHER INFORMATION
 
ITEM 1. LEGAL PROCEEDINGS ITEM 1.
 
We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 15 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2014 Annual Report. During the quarter ended September 30, 2014, there were no materialMaterial developments in the status of those proceedings except asduring the quarter ended March 31, 2015 are described below.in Part I. Item 1. "Financial Information" under Note 15 — Commitments and Contingencies in this Quarterly Report. We believe that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on our financial position or on our results of operations.
The Company and its wholly owned subsidiary are defendants in a lawsuit brought by John C. McCarthy et. al in the fifth District Court of Richland Parish, Louisiana in July 2011. The plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006. On March 29, 2012, the Fifth District Court dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiff’s claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. The plaintiffs are seeking cancellation of the transaction and monetary damages. We subsequently filed a second motion pleading “no cause of action,” with which the district court again agreed and dismissed the plaintiffs’ case on September 23, 2013. Plaintiffs again filed an appeal in November 2013. In October 2014, the appellate court reversed the district court. We subsequently filed for a rehearing.

As previously reported, on August 23, 2012, we and our wholly-owned subsidiary, NGS Sub Corp., and Robert S. Herlin, our President and Chief Executive Officer, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones (the “Jones lawsuit”) in the Western District Court of the Monroe Division, Louisiana. The plaintiffs allege primarily that we (defendants) wrongfully purchased the plaintiffs’ 0.048119 overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for EOR. The plaintiffs are seeking rescission of the assignment of the overriding royalty interest and monetary damages. We believe that the claims are without merit and are not timely, and we are vigorously defending against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the plaintiffs to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the plaintiffs' claims were valid on their face. On September 25, 2013, plaintiff Jones filed a motion to alter or amend the September 17, 2013 judgment. On December 27, 2013, the court denied said plaintiffs’ motion, and on January 21, 2014, we filed a motion to reconsider the nondismissal of the remaining claims, which was denied. Counsel has advised us that, based on information developed to date, the risk of loss in this matter is remote.

On December 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd 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 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 owed Denbury additional revenue interests pursuant to the 2006 agreements and that our transfer 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.

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, a resident of Louisiana, alleging that a former subsidiary of NGS Sub. Corp. improperly disposed of water from an off-lease well into a well located on the plaintiff’s land in Winn Parish in 2006. The plaintiff is requesting monetary damages and other relief. NGS Sub. Corp. disposed of the property in question along with its ownership of the subsidiary in 2008 to a third party. We have denied the claims.



20
Table of Contents

ITEM 1A. RISK FACTORS
 
Our Annual Report on Form 10-K for the year ended June 30, 2014 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2014.
 
ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

During the quarter ended September 30, 2014,March 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 September 30, 2014,March 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 andand/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.
Period 
(a) Total Number of
Shares (or Units)
Purchased
 
(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
July 1, 2014 to July 31, 2014 99 shares of Common Stock $10.94
 Not applicable Not applicable
August 1, 2014 to August 31, 2014 none   Not applicable Not applicable
September 1, 2014 to September 30, 2014 5,530 shares of Common Stock $9.83
 Not applicable Not applicable
Period
(a) Total Number of
Shares (or Units)
Purchased
(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 January 2015none___Not applicableNot applicable
Month of February 2015none___Not applicableNot applicable
Month of March 2015756 shares of Common Stock$6.48Not applicableNot applicable

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
 
Not applicable.
 
ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.
 
ITEM 5. OTHER INFORMATION
 
None.


2126
Table of Contents

ITEM 6. EXHIBITS
 
A.           Exhibits
 
4.1Form of Contingent Performance Stock Grant under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (Filed herein)
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
101.LAB XBRL Taxonomy Extension Label Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document


2227
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 Financial Officer
   Principal Financial Officer and
   Principal Accounting Officer
   
Date: November 7, 2014May 8, 2015  


2328