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 MarchDecember 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 May 5, 2015,February 2, 2016, was 32,909,331.32,881,445.



EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
 
TABLE OF CONTENTS
 
  Page
   
   
   
 
 
 
 
 
   
   
   
   
   
   
   
   
   
   
   
   
 



1

Table of Contents

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

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


March 31,
2015
 June 30,
2014
December 31,
2015
 June 30,
2015
Assets 
  
 
  
Current assets 
  
 
  
Cash and cash equivalents$20,391,495
 $23,940,514
$16,325,013
 $20,118,757
Receivables2,686,686
 1,457,212
2,557,731
 3,122,473
Deferred tax asset159,624
 159,624

 82,414
Derivative assets, net1,323,749
 
Prepaid expenses and other current assets650,826
 747,453
396,018
 369,404
Total current assets23,888,631
 26,304,803
20,602,511
 23,693,048
Oil and natural gas property and equipment, net (full-cost method of accounting)40,349,940
 37,822,070
49,049,250
 45,186,886
Other property and equipment, net308,411
 424,827
38,279
 276,756
Total property and equipment40,658,351
 38,246,897
49,087,529
 45,463,642
Other assets662,247
 464,052
225,355
 726,037
Total assets$65,209,229
 $65,015,752
$69,915,395
 $69,882,727
Liabilities and Stockholders’ Equity 
  
 
  
Current liabilities 
  
 
  
Accounts payable$4,556,114
 $441,722
$4,902,135
 $8,173,878
Accrued liabilities and other1,262,275
 855,373
Derivative liabilities, net
 109,974
Deferred income taxes367,661
 
State and federal income taxes payable116,343
 
342,930
 190,032
Accrued liabilities and other789,692
 2,558,004
Total current liabilities5,462,149
 2,999,726
6,875,001
 9,329,257
Long term liabilities 
  
 
  
Deferred income taxes10,834,844
 9,897,272
10,244,897
 11,242,551
Asset retirement obligations749,252
 205,512
692,976
 715,767
Deferred rent22,861
 35,720

 18,575
Total liabilities17,069,106
 13,138,230
17,812,874
 21,306,150
Commitments and contingencies (Note 15)

 

Commitments and contingencies (Note 16)

 

Stockholders’ equity 
  
 
  
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at 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
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at December 31, 2015 and June 30, 2015 with a liquidation preference of $7,932,975 ($25.00 per share)317
 317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,881,445 shares and 32,845,205 as of December 31, 2015 and June 30, 2015, respectively32,881
 32,845
Additional paid-in capital36,489,885
 34,632,377
40,063,167
 36,847,289
Retained earnings11,617,012
 17,212,213
12,006,156
 11,696,126
Total stockholders’ equity48,140,123
 51,877,522
52,102,521
 48,576,577
Total liabilities and stockholders’ equity$65,209,229
 $65,015,752
$69,915,395
 $69,882,727
 

See accompanying notes to consolidated condensed financial statements.

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Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
 
Three Months Ended 
 March 31,
 Nine Months Ended 
 March 31,
Three Months Ended 
 December 31,
 Six Months Ended 
 December 31,
2015 2014 2015 20142015 2014 2015 2014
Revenues 
  
  
  
 
  
  
  
Delhi field$7,039,868
 $4,185,156
 $18,553,301
 $12,745,203
$6,558,215
 $7,644,831
 $13,854,601
 $11,513,433
Artificial lift technology24,821
 151,052
 203,913
 483,037
64,712
 63,236
 147,732
 179,092
Other properties
 798
 20,369
 134,754

 
 
 20,369
Total revenues7,064,689
 4,337,006
 18,777,583
 13,362,994
6,622,927
 7,708,067
 14,002,333
 11,712,894
Operating costs 
  
  
  
 
  
  
  
Production costs - Delhi field2,932,946
 
 5,750,812
 
2,226,141
 2,817,866
 4,784,028
 2,817,866
Production costs - artificial lift technology267,906
 209,742
 656,819
 526,712
53,731
 191,553
 113,245
 388,913
Production costs - other properties639
 143,887
 98,051
 481,697

 9,390
 1,046
 97,412
Depreciation, depletion and amortization1,138,502
 311,815
 2,425,609
 948,656
1,471,571
 917,757
 2,689,844
 1,287,107
Accretion of discount on asset retirement obligations10,924
 9,631
 23,697
 34,977
11,517
 8,137
 22,860
 12,773
General and administrative expenses *1,467,782
 2,304,397
 4,578,876
 6,875,430
2,057,521
 1,606,501
 3,742,366
 3,111,094
Restructuring charges **
 
 (5,431) 1,332,186
Restructuring charges**1,257,433
 (5,431) 1,257,433
 (5,431)
Total operating costs5,818,699
 2,979,472
 13,528,433
 10,199,658
7,077,914
 5,545,773
 12,610,822
 7,709,734
Income from operations1,245,990
 1,357,534
 5,249,150
 3,163,336
Income (loss) from operations(454,987) 2,162,294
 1,391,511
 4,003,160
Other 
  
  
  
 
  
  
  
Gain on settled derivative instruments, net1,298,201
 
 2,164,628
 
Gain on unsettled derivative instruments, net361,761
 
 1,433,723
 
Delhi field insurance recovery related to pre-reversion event
 
 1,074,957
 
Interest income7,401
 7,383
 27,826
 22,787
5,853
 7,662
 11,665
 20,425
Interest (expense)(24,625) (17,605) (55,244) (50,700)(18,666) (12,159) (37,126) (30,619)
Income before income taxes1,228,766
 1,347,312
 5,221,732
 3,135,423
1,192,162
 2,157,797
 6,039,358
 3,992,966
Income tax provision494,180
 423,612
 2,118,218
 1,148,155
368,889
 917,879
 2,123,858
 1,624,038
Net income attributable to the Company$734,586
 $923,700
 $3,103,514
 $1,987,268
823,273
 1,239,918
 3,915,500
 2,368,928
Dividends on preferred stock168,575
 168,575
 505,726
 505,726
168,576
 168,576
 337,151
 337,151
Net income available to common stockholders$566,011
 $755,125
 $2,597,788
 $1,481,542
$654,697
 $1,071,342
 $3,578,349
 $2,031,777
Earnings per common share              
Basic$0.02
 $0.02
 $0.08
 $0.05
$0.02
 $0.03
 $0.11
 $0.06
Diluted$0.02
 $0.02
 $0.08
 $0.05
$0.02
 $0.03
 $0.11
 $0.06
Weighted average number of common shares 
  
  
  
 
  
  
  
Basic32,861,001
 32,358,163
 32,789,157
 30,328,344
32,741,166
 32,825,631
 32,729,705
 32,754,016
Diluted32,958,218
 32,732,049
 32,909,981
 32,503,460
32,802,440
 32,947,280
 32,789,461
 32,884,754
 
* General and administrative expenses for the three months ended MarchDecember 31, 2015 and 2014 included non-cash stock-based compensation expense of $227,507$212,724 and $444,981,$245,020, respectively. For the corresponding ninesix month periods, non-cash stock-based compensation expense was $715,864$430,839 and $1,134,841,$488,357, respectively.

** Restructuring charges for the nine months ended March 31, 2014 includedinclude $569,228 of non-cash impairment charges and $59,339 of non-cash stock-based compensation expense of $376,365. Forfor the three months and six months ended MarchDecember 31, 2014, restructuring charges contained no stock-based compensation expense.

See accompanying notes to consolidated condensed financial statements.

2015.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
 
Nine Months Ended 
 March 31,
Six Months Ended 
 December 31,
2015 20142015 2014
Cash flows from operating activities 
  
 
  
Net income attributable to the Company$3,103,514
 $1,987,268
$3,915,500
 $2,368,928
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Depreciation, depletion and amortization2,462,087
 980,589
2,714,162
 1,311,425
Impairments included in restructuring charge569,228
 
Stock-based compensation715,864
 1,134,841
430,839
 488,357
Stock-based compensation related to restructuring
 376,365
Stock-based compensation included in restructuring charge59,339
 
Accretion of discount on asset retirement obligations23,697
 34,977
22,860
 12,773
Settlements of asset retirement obligations(223,565) (73,646)
 (220,522)
Deferred income taxes937,572
 998,367
(547,579) 656,589
Deferred rent(12,859) (12,859)
 (8,574)
(Gain) on derivative instruments, net(3,598,351) 
Write-off of deferred loan costs50,414
 
Changes in operating assets and liabilities: 
  
 
  
Receivables from oil and natural gas sales(1,007,058) 88,146
1,176,758
 (1,454,866)
Receivables other(222,416) (3,679)(9,367) (12,492)
Due from joint interest partner
 70,083
Prepaid expenses and other current assets96,627
 (376,501)(119,515) 69,697
Accounts payable and accrued expenses629,760
 690,360
(310,054) 1,384,201
Income taxes payable116,343
 (233,548)152,898
 45,392
Net cash provided by operating activities6,619,566
 5,660,763
4,507,132
 4,640,908
Cash flows from investing activities 
  
 
  
Derivative settlements received1,561,979
 
Proceeds from asset sales389,166
 542,349

 389,166
Maturity of certificate of deposit
 250,000
Capital expenditures for oil and natural gas properties(2,432,424) (989,616)(8,650,217) (1,136)
Capital expenditures for other property and equipment(320,936) (12,793)
 (311,075)
Other assets(183,877) (181,751)(161,345) (84,341)
Net cash used in investing activities(2,548,071) (391,811)(7,249,583) (7,386)
Cash flows from financing activities 
  
 
  
Proceeds on exercise of stock options141,600
 3,162,801
Cash dividends to preferred stockholders(505,726) (505,726)(337,151) (337,151)
Cash dividends to common stockholders(8,192,989) (6,462,269)(3,268,319) (6,565,350)
Stock exchanged for payroll tax liabilities(63,556) (1,591,765)
Acquisition of treasury stock(1,354,743) (58,660)
Tax benefits related to stock-based compensation1,063,827
 108,473
3,910,163
 921,581
Deferred loan costs(63,737) (40,334)
Other67
 6,850
(1,243) (11,292)
Net cash used in financing activities(7,620,514) (5,321,970)(1,051,293) (6,050,872)
Net decrease in cash and cash equivalents(3,549,019) (53,018)(3,793,744) (1,417,350)
Cash and cash equivalents, beginning of period23,940,514
 24,928,585
20,118,757
 23,940,514
Cash and cash equivalents, end of period$20,391,495
 $24,875,567
$16,325,013
 $22,523,164

Supplemental disclosures of cash flow information:Nine Months Ended 
 March 31,
Six Months Ended 
 December 31,
2015 20142015 2014
Income taxes paid$100,000
 $755,941
$440,000
 $100,000
Louisiana carryback income tax refund and related interest received$1,556,999
 $
Non-cash transactions: 
  
 
  
Change in accounts payable used to acquire property and equipment1,877,830
 (241,094)(2,442,183) 1,410,420
Deferred loan costs charged to oil and gas property costs108,472
 
Oil and natural gas property costs incurred through recognition of asset retirement obligations573,689
 45,172

 562,482
Previously acquired Company common shares swapped by holders to pay stock option exercise price
 618,606
Settlement of accrued treasury stock purchases(170,283) 
Royalty rights acquired through non-monetary exchange of patent and trademark assets108,512
 
 
See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statement of Changes in Stockholders' Equity
For the NineSix Months Ended MarchDecember 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
Balance at June 30, 2015317,319
 $317
 32,845,205
 $32,845
 $36,847,289
 $11,696,126
 $
 $48,576,577
Issuance of restricted common stock
 
 213,466
 214
 (147) 
 
 67

 
 272,098
 272
 (239) 
 
 33
Exercise of stock options
 
 87,000
 87
 141,513
 
 
 141,600
Stock exchanged for payroll tax liabilities
 
 (6,781) 
 
 
 (63,556) (63,556)
Forfeitures of restricted stock
 
 (31,467) (31) 31
 
 
 
Acquisition of treasury stock
 
 (204,391) 
 
 
 (1,184,460) (1,184,460)
Retirements of treasury stock
 
 
 (7) (63,549) 
 63,556
 

 
 
 (205) (1,184,255) 
 1,184,460
 
Stock-based compensation
 
 
 
 715,864
 
 
 715,864

 
 
 
 490,178
 
 
 490,178
Tax benefits related to stock-based compensation
 
 
 
 1,063,827
 
 
 1,063,827

 
 
 
 3,910,163
 
 
 3,910,163
Net income attributable to the Company
 
 
 
 
 3,103,514
 
 3,103,514

 
 
 
 
 3,915,500
 
 3,915,500
Common stock cash dividends
 
 
 
 
 (8,192,989) 
 (8,192,989)
 
 
 
 
 (3,268,319) 
 (3,268,319)
Preferred stock cash dividends
 
 
 
 
 (505,726) 
 (505,726)
 
 
 
 
 (337,151) 
 (337,151)
Balance, March 31, 2015317,319
 $317
 32,909,331
 $32,909
 $36,489,885
 $11,617,012
 $
 $48,140,123
Balance at December 31, 2015317,319
 $317
 32,881,445
 $32,881
 $40,063,167
 $12,006,156
 $
 $52,102,521


 See accompanying notes to consolidated condensed financial statements.


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Evolution Petroleum Corporation And Consolidated Subsidiaries
 Notes to Unaudited Consolidated Condensed Financial Statements




Note 1 Organization and Basis of Preparation
 
Nature of Operations.  Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of 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 20142015 Annual Report on Form 10-K for the fiscal year ended June 30, 2014,2015, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.
 
Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity.
 
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

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

Note 2 — Restructuring Charge

Separation of GARP Artificial Lift Technology Operations

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


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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


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

Other Restructuring Impairments

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

Note 3 — Receivables

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

 December 31,
2015
 June 30,
2015
Receivables from oil and gas sales$1,945,397
 $3,122,155
Receivable from settled derivatives602,649
 
Other9,685
 318
Total receivables$2,557,731
 $3,122,473

Note 4 — Prepaid Expenses and Other Current Assets

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

 December 31,
2015
 June 30,
2015
Prepaid insurance$133,927
 $178,994
Equipment inventory (a)
 81,538
Retainers and deposits26,978
 26,978
Prepaid federal and state income taxes204,694
 22,542
Other prepaid expenses30,419
 59,352
Prepaid expenses and other current assets$396,018
 $369,404

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


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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 45 Property and Equipment
 
As of MarchDecember 31, 2015 and June 30, 20142015 our oil and natural gas properties and other property and equipment consisted of the following:
March 31,
2015
 June 30,
2014
December 31,
2015
 June 30,
2015
Oil and natural gas properties 
  
 
  
Property costs subject to amortization$51,722,157
 $47,166,282
$64,024,239
 $57,718,653
Less: Accumulated depreciation, depletion, and amortization(11,372,217) (9,344,212)(14,974,989) (12,531,767)
Unproved properties not subject to amortization
 

 
Oil and natural gas properties, net$40,349,940
 $37,822,070
$49,049,250
 $45,186,886
Other property and equipment 
  
 
  
Furniture, fixtures and office equipment, at cost$288,732
 $343,178
Artificial lift technology equipment, at cost330,525
 377,943
Other equipment, at cost$337,245
 $607,674
Less: Accumulated depreciation(310,846) (296,294)(298,966) (330,918)
Other property and equipment, net$308,411
 $424,827
Other equipment, net$38,279
 $276,756
 
During the ninesix months ended ended MarchDecember 31, 2015 wethe Company incurred $225,883capital expenditures of costs related to$6.3 million for the installation of our artificial lift technology, GARP®,Delhi field, including approximately $4.4 million for the NGL plant project which is currently in progress. We have incurred approximately $9.4 million on a cumulative basis for the remaining two wellsNGL plant out of a five-well program for a third-party customer. Under the contract for these installations, we fund the majoritytotal authorized commitment 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 timing and amounts of our expected net revenues from the wells. $24.6 million.

During the ninethree months ended MarchDecember 31, 2015, we recorded additional depreciationa charge of $273,301 reflecting$210,392 to expense the impairmentremaining capitalized costs of unrecovered installation costs ofcertain artificial lift equipment net of estimated residual salvage value, which had been removed from threeinstalled in the wells of a third-party customer. ArtificialWe continue to own this equipment and contract rights, but do not expect to realize any significant future value from this investment at current prices.
Note 6Other Assets

As of December 31, 2015 and June 30, 2015 other assets consisted of the following:
 December 31,
2015
 June 30,
2015
Royalty rights$108,512
 $
Investment in Well Lift Inc., at cost108,750
 
Trademarks
 44,803
Patent costs
 538,276
Less: Accumulated amortization of patent costs
 (47,063)
Deferred loan costs179,468
 337,078
Less: Accumulated amortization of deferred loan costs(171,375) (147,057)
Other assets, net$225,355
 $726,037
During the quarter ended September 30, 2015, our plan to obtain a new expanded secured credit facility was postponed due to market conditions. As a result, the Company determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $108,472 of deferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. As discussed in Note 15, the Company is in discussions with the Lender to extend the maturity, renew the current unsecured Credit Agreement or seek a similar source of bank financing. As of December 31, 2015, there were $8,093 of unamortized deferred loan costs related to our existing unsecured credit facility.
See Note 2 for discussion of transactions associated with the separation of our GARP® artificial lift equipmenttechnology operations.
The company accounts for its investment in WLI using the cost method under which any return of capital reduces cost and corresponding accumulated depreciationany dividends paid are recorded as income. This investment is considered a level 3 fair value measurement and its value will be evaluated for impairment periodically and when management identifies any events or changes in circumstances that might have both been reduced bya significant adverse effect on the $273,301 impairment.fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.

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 Notes to Unaudited Consolidated Condensed Financial Statements



Note 5Other Assets

As of March 31, 2015 and June 30, 2014 our other assets consisted of the 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 67 Accrued Liabilities and Other
 
As of MarchDecember 31, 2015 and June 30, 20142015 our other current liabilities consisted of the following:
March 31,
2015
 June 30,
2014
December 31,
2015
 June 30,
2015
Accrued incentive and other compensation$566,465
 $1,358,653
$366,967
 $578,910
Accrued restructuring charges
 530,412
Officer retirement costs
 288,258
Asset retirement obligations due within one year10,219
 146,703
102,874
 57,223
Accrued royalties69,344
 89,179
Accrued royalties, including suspended accounts45,999
 75,164
Accrued franchise taxes94,473
 87,575
63,792
 94,885
Accrued restructuring charge628,866
 
Other accrued liabilities49,191
 57,224
53,777
 49,191
Accrued liabilities and other$789,692
 $2,558,004
$1,262,275
 $855,373
 
Note 7 — Restructuring
On November 1, 2013, we undertook an initiative to refocus our business to 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.  All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges is as follows:

Type of Cost
Balance at
December 31,
2013
 Payments Adjustment to Cost Balance at
December 31,
2014
Salary continuation liability$615,721
 $(615,721) $
 $
Incentive compensation costs185,525
 (185,525) 
 
Other benefit costs and employer taxes154,575
 (110,144) (44,431) 
Accrued restructuring charges$955,821
 $(911,390) $(44,431) $



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Notes to Unaudited Consolidated Condensed Financial Statements


Note 8 Asset Retirement Obligations
 
Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and
remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a
reconciliation of the beginning and ending asset retirement obligations for the ninesix months ended MarchDecember 31, 2015, and for the year ended June 30, 2014:2015:
Nine Months Ended 
 March 31, 2015
 Year Ended
June 30,
2014
December 31,
2015
 June 30,
2015
Asset retirement obligations — beginning of period$352,215
 $615,551
$772,990
 $352,215
Liabilities sold(52,526) (48,273)
Liabilities incurred (a)564,019
 

 564,019
Liabilities settled(137,604) (323,665)
 (137,604)
Liabilities sold
 (52,526)
Accretion of discount23,697
 41,626
22,860
 34,866
Revision of previous estimates9,670
 66,976

 12,020
Less obligations due within one year(10,219) (146,703)
Asset retirement obligations — end of period$749,252
 $205,512
$795,850
 $772,990
Less current portion in accrued liabilities(102,874) (57,223)
Long-term portion of asset retirement obligations692,976
 715,767
 
(a) Liabilities incurred during the periodfiscal 2015 relate to our share of the the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.

Note 9—9 — Stockholders’ Equity

 Common Stock Dividends and Buyback Program
 
Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. During the ninesix months ended MarchDecember 31, 2015, the Company declared threetwo quarterly dividends on its common stock and paid $8,192,989$3,268,319 to its common stockholders. 


For the nine months ended March 31,On May 12, 2015, the Board of Directors authorized the issuanceapproved a share repurchase program covering up to $5 million 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 and issued 25,740 shares of restricted common stock as compensation to the Company's directors. See Note 10 - Stock-Based Incentive Plan.common stock. Commencing in June 2015, 265,762 shares have been repurchased at an average price of $6.05 per share (totaling $1,609,008) including 202,390 shares purchased during the six months ended December 31, 2015, at an average price of $5.80 (totaling $1,173,899). Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled.

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Notes to Unaudited Consolidated Condensed Financial Statements



 Series A Cumulative Perpetual Preferred Stock
 
At MarchDecember 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 afterEffective July 1, 2014, we can redeem this preferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends.  With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt.  Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $505,726 and $505,726$337,151 to holders of our Series A Preferred Stock during each of the nine monthssix month periods ended MarchDecember 31, 2015 and 2014, respectively.2014.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2014,2015, 100% of cash dividends on preferred and common stock were treated for tax purposesas qualified dividend income. Approximately 86% of cash dividends on common shares were treated as a return of capital to our stockholders.stockholders and the remainder of 14% were treated as qualified dividend income. Based on our current projections for the fiscal year ending June 30, 2015,2016, we expect all preferred and common dividends will be treated as qualified dividend income and that a portion of our cash dividends on common stock will be treated as a return of capital and the remainder as qualified dividend income. We will make a preliminary determination regar

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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 10—10 — Stock-Based Incentive Plan
 
We may grantUnder the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), andcontingent restricted common stock awards ("Contingent Restricted Stock") and/or 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").Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration on October 24, 2017 and 542,529257,188 shares remain available for grant as of MarchDecember 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 MarchDecember 31, 2015, and the changes during the fiscal year:period:
 Number of Stock
Options
and Incentive
Warrants
 Weighted Average
Exercise Price
 Aggregate
Intrinsic Value
(1)
 Weighted
Average
Remaining
Contractual
Term (in
years)
Stock Options outstanding at July 1, 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

 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, 201591,061
 $2.50
  
  
Expired(5,830) 4.02
    
   Stock Options outstanding at December 31, 201585,231
 2.40
 $205,305
 0.9
   Vested and exercisable at December 31, 201585,231
 $2.40
 $205,305
 0.9
(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($5.954.81 as of MarchDecember 31, 2015) and the Stock Option exercise price of in-the-money Stock Options.

Restricted Stock and Contingent Restricted Stock

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

During the nine months ended March 31,In August 2014 and in December 2015, the Company awarded grants of both Restricted Stock and contingentContingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were

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Notes to Unaudited Consolidated Condensed Financial Statements


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

Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company upon vesting.through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the four- year term. As of MarchDecember 31, 2015, the Company doescertain performance-based awards were not consider theconsidered probable of vesting of these performance-based grants to be probablefor accounting purposes and no compensation expense has been recognized.recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period.

Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting

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Notes to Unaudited Consolidated Condensed Financial Statements


period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Fair values for theseDuring the six months ended December 30, 2015, we granted market-based awards rangedwith fair values ranging from $2.93 to $5.07, all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance.  During fiscal year 2015, we had granted market-based awards with fair values ranging from $4.26 to $8.40 and with expected vesting periods of 3.30 years to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

Unvested Restricted Stock awards at December 31, 2015 consisted of the following:
Award Type Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Service-based awards 214,269
 7.50
Performance-based awards 120,386
 7.92
Market-based awards 93,254
 5.50
Unvested at December 31, 2015 427,909
 $7.18
The following table sets forth the Restricted Stock transactions for the ninesix months ended MarchDecember 31, 2015:
 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
 Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2015262,227
 $9.37
    
Service-based shares granted142,594
 6.09
    
Performance-based shares granted64,752
 6.09
    
Market-based shares granted64,752
 4.58
    
Vested(74,949) 8.62
    
Forfeited(31,467) 9.39
    
Unvested at December 31, 2015427,909
 $7.18
 $2,298,812
 2.9
(1) Excludes $559,121 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

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Notes to Unaudited Consolidated Condensed Financial Statements


Unvested Contingent Restricted Stock awards at December 31, 2015 consisted of the following:
Award Type Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Performance-based awards 60,196
 $7.92
Market-based awards 46,630
 3.34
Unvested at December 31, 2015 106,826
 $5.92
The following table sets forth Contingent Restricted Stock transactions for the six months ended December 31, 2015:
 Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 201556,286
 $8.20
    
Performance-based awards granted32,376
 6.09
    
Market-based awards granted32,376
 2.93
    
Forfeited(14,212) 8.54
    
Unvested at December 31, 2015106,826
 $5.92
 $128,898
 3.2
(1) Excludes $770,252$476,761 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

The following table summarizes contingent Restricted Stock activity:
 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
    
Market-based awards granted17,961
 4.26
    
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 for which vesting is not considered probable at this time for accounting purposes.

Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the three months ended MarchDecember 31, 2015 and 2014 was $242,835$272,063 and $444,981,$245,020, respectively. Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants forFor the Stock-based compensation expense related to Restricted Stock and contingent Restricted Stock grants for the ninesix months ended MarchDecember 31, 2015 and 2014, was $731,192 and $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.

was $490,178 and $488,357, respectively.
Note 11Derivatives
In early June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for a substantial portion of its near-term forecasted production to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The costless collars the Company uses to manage risk are designed to establish floor and ceiling prices on anticipated future oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We also use swap agreements in which we exchange our exposure to floating crude spot prices for a fixed price for our production over a period of time.
The Company does not enter into derivative instruments for speculative or trading purposes.
The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedging under which the Company records the fair value of the instruments on the balance sheet at each reporting date with changes in fair value recognized in income.  Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815.  Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings.
These derivative instruments can result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value derivative instruments where the Company is in a net asset position with its counterparty as of December 31, 2015 totaled $1,323,749. Refer to Note 12—Fair Value Measurement for derivative asset and derivative liability balances before offsetting.
The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As

12

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Notes to Unaudited Consolidated Condensed Financial Statements


such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.
For the six months ended December 31, 2015, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $3,598,351 consisting of a realized gain of $2,164,628 on settled derivatives and an unrealized net gain of $1,433,723 on unsettled derivatives.
The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of December 31, 2015.
Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl.
Months of January 2016 through March 2016 Fixed Price Swap 1,100 $51.65
Subsequent to December 31, 2015, the Company realized a gain of $677,703 on derivative contracts which expired at the end of January 2016. We had previously recorded an unrealized gain of $483,839 on these contracts as of December 31, 2015.
Note 12 Fair Value Measurement

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

The three levels are defined as follows:

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Notes to Unaudited Consolidated Condensed Financial Statements



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

Level 2 — 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 — 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 InstrumentsDerivative Instruments.. The Company’s other financial instruments consist of cashfollowing table summarize the location and cash equivalents, certificates of deposit, receivables and payables. The carrying amounts of cashthe Company’s assets 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 obligationsliabilities measured at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs usedon a recurring basis as presented in the calculationconsolidated balance sheets as of asset retirement obligations includeDecember 31, 2015. All items included in the coststables below are Level 2 inputs within the fair value hierarchy:
  December 31, 2015
Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets $1,323,749
 $
 $1,323,749
Current derivative liabilities 
 
 
Total $1,323,749
 $
 $1,323,749
The fair values of pluggingthe Company’s derivative assets and abandoning wells, surface restorationliabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and reserve lives. Subsequentgas, discount rates and volatility factors. The fair values are also compared to initial recognition, revisions to estimated asset retirement obligationsthe values provided by the counterparty for reasonableness and are made when changes occuradjusted for input values, which we review quarterly.

the counterparty's credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.
Note 1213 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.
 

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Notes to Unaudited Consolidated Condensed Financial Statements


There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the ninesix months ended MarchDecember 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, 20102012 through June 30, 2014.2014 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2014 for state tax purposes.
 
Our effective tax rate for any period maywill typically differ from the statutory federal rate due to (i) ouras a result of state income tax liabilitytaxes, primarily in Louisiana; (ii) stock-based compensation expensethe state of Louisiana, with smaller differences related to qualified incentive stock option awards (“ISO awards”), which createsbased compensation and other permanent differences. Statutory percentage depletion gives rise to a permanent difference in our tax differencerates when utilized for financial reporting, as these types of awards, if certain conditions are met, are not deductible forstate or federal income tax purposes; and (iii) statutory percentage depletion, which may create a permanent tax difference for financial reporting.purposes.

BasedIn late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We also received $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resultingresulted from the exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we filed a requestrecognized this benefit as an increase in additional paid-in capital 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.financial reporting purposes. This carryback will utilizeutilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes, with $5.1 millionpurposes. The remaining balance of this net loss carryforward in Louisiana was utilized in the tax loss carryforwards remainingreturn 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.year ended June 30, 2015.
 
We recognized income tax expense of $2,118,218$2,123,858 and $1,148,155$1,624,038 for the ninesix months ended MarchDecember 31, 2015 and 2014, respectively, with corresponding effective rates of 40.6%35% and 36.6%41%. The lower effective tax rate in 2015 resulted from a lesser amount of taxable income in the state of Louisiana.
Note 14 —Net Income Per Share
The following table sets forth the computation of basic and diluted income per share:
 Three Months Ended December 31, Six Months Ended December 31,
 2015 2014 2015 2014
Numerator 
  
  
  
Net income available to common shareholders$654,697
 $1,071,342
 $3,578,349
 $2,031,777
Denominator 
  
  
  
Weighted average number of common shares — Basic32,741,166
 32,825,631
 32,729,705
 32,754,016
Effect of dilutive securities: 
  
  
  
   Contingent restricted stock grants9,795
 6,432
 9,322
 1,785
   Stock options51,479
 115,217
 50,434
 128,953
Weighted average number of common shares and dilutive potential common shares used in diluted EPS32,802,440
 32,947,280
 32,789,461
 32,884,754
        
Net income per common share — Basic$0.02
 $0.03
 $0.11
 $0.06
Net income per common share — Diluted$0.02
 $0.03
 $0.11
 $0.06
Outstanding potentially dilutive securities as of December 31, 2015 were as follows:
Outstanding Potential Dilutive Securities Weighted
Average
Exercise Price
 At December 31, 2015
Contingent Restricted Stock grants (a) $
 46,630
Stock Options 2.40
 85,231
  $1.55
 131,861
 

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 Notes to Unaudited Consolidated Condensed Financial Statements


Note 13 —Net Income Per Share
The following table sets forth the computation of basic and diluted income (loss) per share:
 Three Months Ended March 31, Nine Months Ended March 31,
 2015 2014 2015 2014
Numerator 
  
  
  
Net income available to common shareholders$566,011
 $755,125
 $2,597,788
 $1,481,542
Denominator 
  
  
  
Weighted average number of common shares — Basic32,861,001
 32,358,163
 32,789,157
 30,328,344
Effect of dilutive securities: 
  
  
  
   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 EPS32,958,218
 32,732,049
 32,909,981
 32,503,460
        
Net income per common share — Basic$0.02
 $0.02
 $0.08
 $0.05
Net income per common share — Diluted$0.02
 $0.02
 $0.08
 $0.05
Outstanding potentially dilutive securities as of March 31, 2015 were as follows:
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 MarchDecember 31, 2014 were as follows:
Outstanding Potential Dilutive SecuritiesWeighted
Average
Exercise Price
 At March 31, 2014 Weighted
Average
Exercise Price
 At December 31, 2014
Stock options$2.02
 228,061
Contingent Restricted Stock grants (a) $
 17,961
Stock Options 2.25
 141,061
 $2.00
 159,022
(a) Contingent Restricted Stock grants for which vesting is not considered probable for accounting purposes are excluded from securities outstanding.
Note 1415 — Unsecured Revolving Credit Agreement
 
On February 29, 2012, EPMEvolution Petroleum Corporation entered into a credit agreementCredit Agreement (the “Credit Agreement”"Credit Agreement") with Texas Capital Bank, N.A. (the “Lender”"Lender"). The Credit Agreement provides usthe Company with a revolving credit facility (the “facility”) in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000.  A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit.
 
The facility is unsecured and has a term of four years, expiring on February 29, 2016.  OurThe Company's subsidiaries guarantee EPM’sthe Company's obligations under the facility. We may use theThe proceeds of any loans under the facility may be used by the Company for the acquisition and development of oil and gas properties, as defined in the facility, the issuance of letters of credit, and for working capital and general corporate purposes.
 
Semi-annually, the borrowing base and a monthly reduction amount are re-determined from 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 in the Credit Agreement.
 
At ourthe Company's option, borrowings under the facility bear interest at a rate of either (i) an Adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rate or the sum of 0.50% andplus 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

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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 reflectingof 3.5% per annum rate applied to theirthe principal amountsamount 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 areThe Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as $50,000 in loan costs incurred upon closing.
 
The Credit Agreement also contains financial covenants including a requirement that wethe Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1.  The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other thatthan 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 Asuch 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 allany amounts outstanding under the Credit Agreement if any, to be immediately due and payable.
 
As of MarchDecember 31, 2015 and 2014, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000, and we are in compliance with all the covenants of the Credit Agreement. During Mayearly 2014 the Lender waived the provisions of the Credit Agreement pertaining to the past payments of cash dividends on our common stock, and the Credit Agreement was amended to permit the payment of cash dividends on common stock in the future if no borrowings are outstanding at the time of such payment.
 
In connection with this agreement, wethe Company incurred $179,468 of debt issuance costs whichthat 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

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issuance costs related to the Credit Agreement was $44,570$8,093 as of MarchDecember 31, 2015. The Company is in discussions with the Lender to replaceextend the maturity, renew the current unsecured Credit Agreement with an expanded secured facility. Asor seek a similar source of March 31, 2015, the Company had incurred approximately $127,272 in legal and title costs related to this proposed agreement, which are also capitalized in Other Assets.

bank financing.
Note 1516 — 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.

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.

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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 Fieldfield 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 CO2CO2 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. In March 2015, we amended and expanded our claims in this matter. This matter is set for trial in April 2016.

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 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 8th8th 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'certain claims against NGS Sub Corp. WeThe plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and arediscovery is in process. We will continue to vigorously defendingdefend all claims by Mr. Hawkinsplaintiffs and do not consider the claimslikelihood of a material loss to the Company.

Company in this matter to be remote.
 

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Notes to Unaudited Consolidated Condensed Financial Statements


Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1,July 31, 2016. Future minimum lease commitments as of MarchDecember 31, 2015 under this operating lease are as follows: 
For the twelve months ended March 31, 
2016$159,011
201753,004
Total$212,015
Twelve months ended December 31, 
2016$92,756
 
Rent expense for the three months ended MarchDecember 31, 2015 and 2014 was $45,857 and $43,776, and $44,473, respectively. Rent expense forFor the ninesix months ended MarchDecember 31, 2015 and 2014, rent expense was $131,327$90,900 and $131,151, respectively.$87,551.

Employment Contracts.Capital Expenditures. We have entered into employment agreements with twoSee Note 5 for discussion of the Company's senior executives. The employment contracts provide for severance paymentscapital projects 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 payprogress 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 March 31, 2015 is approximately $473,000.expected remaining capital commitments.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 20142015 (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 20142015 Annual Report on Form 10-K for the year ended June 30, 20142015 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 stockholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our stockholders, and a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership in our common stock.

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

We are currently funding our fiscal 20152016 capital program from working capital and net cash flows from our properties.
 
Highlights for our ThirdSecond Quarter of Fiscal 20152016 and ProjectOperations Update

"Q3-15" & "currentCurrent quarter" referrefers to the three months ended MarchDecember 31, 2015, the Company's 3rd2nd quarter of fiscal 2015.2016.

"Q2-15" & "priorPrior quarter" referrefers to the three months ended September 30, 2015, the Company's 1st quarter of fiscal 2016.

"Year-ago quarter" refers to the three months ended December 31, 2014, the Company's 2nd2nd quarter of fiscal 2015.
Highlights

"Q3-14" & "year-ago quarter" referNet income to the three months ended March 31, 2014, the Company's 3rd quarter of fiscal 2014.
Operations

For Q3-15, the Company earned $0.6common shareholders was $0.7 million of net income, or $0.02 per diluted common share,share.

Delhi net production increased to 1,801 barrels of oil per day (“BOPD”), a 25% decrease from the year-ago quarter and a 47% decrease from6% increase over the prior quarter. Gross production in the field increased to 6,810 BOPD from 6,423 BOPD in the prior quThe significant declinearter.

Average realized oil price was $39.59 per barrel, down from $46.70 per barrel 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 resultresulting in Delhi revenues of our reversionary working interest at Delhi.

Current quarter revenues were $7.1$6.6 million a 63% increase from the year-ago quarter and an 8% decrease fromcompared to $7.3 million in the prior quarter. The increase from the year-ago quarter was due to net revenues associated with the reversion
Realized hedge gains added $1.3 million, or $7.84 per barrel, which are reported as other income and not included in revenues.

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

We successfully completed the separation and transfer of our GARP® artificial lift technology operations, resulting in a one-time personnel restructuring charge of $0.7 million and a non-cash impairment charge of $0.6 million. The recurring annual overhead cost savings to the Company are estimated to be approximately $1.0 million per year.
Net working 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 volumescapital remains strong at Delhi for three months versus only two months of working interest sales based$13.7 million, and Evolution declared its tenth consecutive quarterly cash dividend on the November 1, 2014 effective date of our reversionary working interest.

Our Delhi production averaged 1,640 net barrels of oil per day (“BOPD”), a 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 the 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 from approximately $102 per barrel in the year-ago quarter, and decreased 32% from approximately $70 per barrel in the prior quarter. Delhi oilpricing is based on Louisiana Light Sweet index, which continues to be valued at a premium compared to West Texas Intermediate.
common shares.

We remain debt-freedebt free.

Full Cost Pool Ceiling Test and distributed $1.6 millionProved Undeveloped Reserves
  For the quarter ended December 31, 2015, our capitalized costs of oil and gas properties were well below the full cost valuation ceiling and we do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarters of fiscal 2016. However, lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash dividendsflows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our common stockholderspetroleum products during the twelve month period ending with the balance sheet date. If commodity prices remain at the current quarter.quarter’s lower levels, the average prices used in future ceiling test calculations will decline.
Our proved undeveloped reserves in the Delhi field consist primarily of the NGL plant and development of the remaining eastern part of the field. The estimated future capital expenditures in the Delhi field are $9.34 per BOE of proved undeveloped reserves. The NGL plant is currently under construction and expanded development of the eastern part of the Delhi field was commenced upon the reversion of our working interest in November 2014. Shortly thereafter, the operator reduced its capital budget and temporarily postponed development of the eastern part of the Delhi field. Resumption of this development project is dependent, at least in part, on the operator's allocation of available capital to projects within their portfolio. Both we and the operator believe that it is prudent to complete the NGL plant before continuing with future development of the field as the plant is projected to improve subsequent field economics. At this time, despite lower commodity price levels, we continue to believe that these projects are economically viable and it is probable they will be executed within the next five years. We base our analysis on the current lifting costs in the field and the relatively low future development costs per BOE. Therefore, we believe these reserves remain properly classified as proved undeveloped reserves under SEC guidelines.
Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2014.2015.
Delhi Field - Enhanced Oil Recovery Project

Gross production at Delhi in the thirdsecond quarter of fiscal 20152016 averaged 6,2036,810 BOPD, aan increase of 1%16% from the year-ago quarter, and a 5%6% increase from the prior quarter. Net production averaged 1,6401,801 BOPD, a 259%52% increase from the year-ago quarter, and a 38%6% increase from the prior quarter. GrossThe large year-over-year increase in net production continues to be positively impacted byvolumes was the result of an increase in both gross production volumes and the reversion of our 23.9% working interest in the Delhi field on November 1, 2014, which means we did not realize a replacement well that was redrilled and placed intofull quarter of production associated with our reversionary working interest in Januarythe second quarter of fiscal 2015.

Field operating expenses were $13.44 per barrel, an 18% reduction from levels in the prior quarter, resulting primarily from lower purchased CO2 costs. In the quarter ending MarchDecember 31, 2015, our net share of the joint interest billed lease operating expenses was approximately $2.9$2.2 million, of which $1.6$1.0 million is related to CO2 purchases and transportation expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of

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8% plus transportation costs of $0.20 per Mcf. Total average CO2 costs per month are down 36%decreased 27% from the prior quarter monthly as result of both lower oil prices and lower purchased CO2 volumes in the quarter. Purchased CO2 gross volumes in the priorcurrent quarter were significantly higher than the expected rates going forward of 90,000 to 95,000averaged 73,312 Mcf per day.day, a decline of 18% from 89,705 Mcf per day in the prior quarter. Despite lower purchased CO2 volumes, the overall oil production has been increasing over the past few quarters. On a total BOE basis, average CO2 costs were down 29%31% from $15.33$8.89 per BOE in the prior quarter to $10.82$6.14 per BOE, primarily due to increased working interestas the result of lower CO2 volumes purchased and lower realized oil prices in the current quarter.prices. Our purchased CO2 costs are directlysubstantially 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 the value of these hydrocarbon products, according toBased on recent discussions with the operator, the increased purityfabrication, construction and installation of the NGL plant are continuing and completion is anticipated in the fourth quarter of calendar 2016. The plant has a total estimated cost of $24.6 million net to the Company, of which approximately $9.4 million had been incurred as of December 31, 2015. The pace of spending on the NGL plant has been slower than originally projected by the operator, as they have been focused on making the best decisions on design and selection of contractors and have attempted to reduce costs in this current low pricing environment for materials and services required for the plant. Consequently, we believe that our ultimate net costs for the project may be below our initial commitment, however this will not be known until the project is completed. The June 30, 2015 reserves report includes projected peak gross proved production volumes of approximately 1,850 barrels of liquids per day from the NGL plant over the next five years, and peak gross probable volumes of 1,140 barrels of liquids per day later next decade. The methane removed by the plant will be utilized to supply power for the NGL plant and reduce electricity costs for the recycling facility. The NGL plant is also expected to increase the sweep efficiency and recovery of the CO2 stream re-injected intoflood, therefore the field should result in significant operational benefits to the CO2 flood and potentially increasereserves report reflects incremental gross crude oil production from existing wells and/or accelerated recoveryvolumes of oil reserves. The NGL plant has an estimated gross cost of $103 million ($24.6 million net toapproximately 500 BOPD once 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 NGL's per day when in full operation and NGL volumes potentially may be higher based on performance and yield.operational.     

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, 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 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 very limited circumstances. This agreement does not settle any of the outstanding litigation

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matters with Denbury, including their counterclaim related to the net revenue interest conveyed in the 2006 Purchase and Sale Agreement.

GARP® - Artificial Lift Technology

During the current quarter, the GARP® installation in the Appelt #1H well, that had been shut-in for overBased on a year due to solids production, was worked over to install better solids handling capacity and thereby restored to producing status at the previous ratestrategic review of approximately 10 barrels of oil per day. The Selected Lands #2 well was also restored to production in the 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 the quarter.
We continue to work diligently to advance the development of the GARP® technology and expect to file three GARP® patents and one provisional GARP® patentartificial lift technology operations, we completed the separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the coming weeksnew entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to solve specificconvert our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future success of the technology, while eliminating our overhead and operating commitments associated with GARP®. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.

This transaction resulted in a one-time personnel restructuring charge of $0.7 million, along with non-cash asset impairments of approximately $0.6 million. The separation will reduce our overhead costs by an estimated $1.0 million per year and remove our obligation to fund the future capital and operating needs identified by customers.
Recent GARP® marketing and business development efforts have secured three master service agreements, including with one major, one super-independent and one large independent oil producer and a fourth agreement is pending.
Approval as a vendor to provide oil field services does not guarantee an agreement to install GARP® technology, which is governed by a separate agreement.    of this operation.

Liquidity and Capital Resources
 
We had $20.4$16.3 million million and $23.9$20.1 million in cash and cash equivalents at MarchDecember 31, 2015 and June 30, 2014,2015, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility at period end.facility.

During the ninesix months ended MarchDecember 31, 2015, we financedfunded our operations with cash generated from operations and cash on hand. At MarchDecember 31, 2015, our working capital was $18.4$13.7 million, compared to working capital of $23.3$14.4 million at June 30, 2014.2015.  The $4.9$0.7 million decrease in working capital decrease isconsists primarily due toof a $4.1$3.8 million increasereduction in cash, partly offset by a $3.3 million decrease in accounts payable reflecting post-reversion Delhi field operating expenses and capital expenditures together with $3.5 million of lower cash, partially offset by $1.6 million of lower accrued liabilities principally attributable to incentive compensation, restructuring and officer retirement accrual declines and $1.0 million of increased accounts receivable primarily due to the interest reversion.other changes in working capital.
 
Cash Flows from Operating Activities
 
For the ninesix months ended MarchDecember 31, 2015, cash flows provided by operating activities were $6.6$4.5 million, which included $0.4reflecting $3.9 million of cash provided by net income, $0.3 million used by other working capital items.  Of the $7.0adjustments reconciling net income to cash provided by operating activities, and $0.9 million provided before other working capitalby changes approximately $3.1 million was due to net income,operating assets and approximately $3.9 million was attributable to non-cash expenses and settlements of asset retirement obligations.liabilities.
    
For the ninesix months ended MarchDecember 31, 2014, cash flows provided by operating activities were $5.7$4.6 million, reflecting $5.4 million provided by operations before $0.2 million provided bywhich included a small impact from changes in other working capital changes.items.  Of the $5.4$4.6 million provided, before other working capital changes, $2.0approximately $2.4 million was due to net income, which includes $1.3 million of restructuring and $0.6 million of retirement obligation charges, and $3.4approximately $2.2 million was attributable to non-cash expenses.
 
Cash Flows from Investing Activities
Investing activities for the nine months ended March 31, 2015 used $2.5 million of cash, consisting primarily of capital expenditures of approximately $2.4 million for Delhi field, $0.3 million for artificial lift technology together with $0.2 million of other assets comprised primarily of GARP® patent costs, partially offset by $0.4 million of proceeds received for the sale of properties in the Mississippi Lime project in October 2014.
Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2014 was $1.0 million. Development activities were about equally divided among GARP® wells in Giddings and the Sneath and Hendrickson wells completed in the Mississippi Lime during the prior year. We received approximately $542,000 of proceeds from asset sales, including $400,000 from the sale of our South Texas properties, and $250,000 of cash from the maturity of a certificate of deposit.


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

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

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

During the six months ended December 31, 2014, we used $7.6$6.1 million in cash for financing activities, consisting principally consisting of cash outflows$6.9 million of $8.2 million for common stock dividend payments to common and $0.5 million for preferred dividend payments,shareholders, offset partially by $1.1$0.9 million of cash provided by tax benefits related to stock-based compensation.

In the nine months ended March 31, 2014, we used $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 and $1.6 million for stock exchanged for payroll tax liabilities and exercise price payments related to incentive stock warrant and stock option exercises and restricted stock vestings.

Capital Budget
Delhi Field
               WithDuring the operator's determination that reversion of our 23.9% working interest and 19.036% net revenue interest in Delhi occurred effective November 1, 2014,six months ended December 31, 2015, we began funding our shareincurred $6.3 million of capital expenditures, inwhich includes $4.4 million for the 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 ofNGL recovery plant, $0.8 million for enhancing well bore integrity, $1.0 million for general maintenance capital within the field and drilling and completion$0.1 million of monitoring wells.leasehold costs.

               ProjectedAs of December 31, 2015, we had incurred approximately $9.4 million of cumulative capital expenditures over the next two fiscal years are currently expected to total approximately $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 and project economics based on current and forward looking oil prices. Of this total, approximately $24.6 million iscosts for the gas processingNGL recovery plant and the balance is for continued developmentout of the CO2 project into the eastern halfan original commitment of the field. We expect these$24.6 million. The remaining committed capital costs of approximately $15.2 million are expected to be incurred over portionsthe remainder of calendar 2016. In addition, there will likely be other spending on unbudgeted capital projects for maintenance or production enhancement during the next twocurrent fiscal years, although these development plans are subjectyear, which we do not expect to review and deferral. Total spending basedhave a material effect on proved reserves in the reserve report, net to our interest, is currently forecast to be up to approximately $50 million over the next four years, which includes the projects above plus further expansion of the CO2 flood patterns.financial position.
GARP® - Artificial Lift Technology
Based on a strategic review of our current marketing and business plans, we expect that our capital requirements forGARP® artificial lift technology operations, will be relatively minor overwe completed the next fiscal year.separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the new entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future success of the technology, while eliminating our overhead and operating commitments associated with GARP®. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.
Liquidity Outlook
Funding for our anticipated capital expenditures during this fiscal year is expected to be met from cash flows from operations and current working capital. We expect to remain debt free under our current operating plans, but we have access to a $5.0 million unsecured revolving line of credit. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs. We are currently seeking to renew the unsecured revolving line of credit or a similar source of bank financing.
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. To date, our BoardIn June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for approximately two-thirds of Directors have followedits forecasted production from July 1, 2015 to December 31, 2015 to achieve a policymore predictable level of not hedgingcash flows to support the Company’s capital expenditure and dividend programs. Costless collars used by the Company to manage risk are designed to establish floor and ceiling prices on a part of anticipated future commodity sales dueoil production. In October 2015, to our having no outstanding debt. Asreduce exposure

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to oil price volatility for approximately two-thirds of forecasted production from January 1, 2016 to March 31, 2016, we acquired a result, ourseries of swaps, which provide a fixed price consisting of identical floor and ceiling prices. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth is heavily influencedare significantly impacted by the prices receivedwe receive for our production. Liquidity could also be affected by any litigation outcome, positive or negative.
FundingThe Board of Directors and management instituted a cash dividend on our common stock in December 2013 at an initial quarterly rate of $0.10 per common share. However, as a result of the decline in oil prices which began in the fall of 2014, combined with the anticipated $24.6 million cost of building and installing the Delhi NGL gas plant during calendar years 2015 and 2016, the Board of Directors concluded it was prudent to adjust the quarterly dividend rate from $0.10 per share to $0.05 per share, effective with the quarter ended March 31, 2015. The reduction in the dividend rate allows the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield. In addition, in May 2015, we established a stock repurchase plan to allow us acquire up to $5.0 million of our anticipated capital expenditurescommon stock over time. The actual timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. There is no fixed termination date for the next two fiscal years is expected torepurchase program, and the repurchase program may be met from cash flows from operations and current working capital. Our preference is to remain debt free absentsuspended or discontinued at any strategic move, but we have access to an unsecured revolving line of credit and have plans to convert this line into a senior secured facility with significantly higher borrowing capacity with an extended term, to 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.
time. Payment of free cash flow in excess of our operating and capital requirements through cash dividends onand repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate. The Board of Directors and management instituted this strategy over a year ago due to our belief that high commodity prices at the time 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 recycle gas processing plant during calendar years 2015 and 2016, the Dividend Committee and the Board of Directors believed it was prudent to adjust the current dividend rate from $0.40 per share annually to $0.20 per share annually, effective in the quarter ending March 31, 2015. The reduction in the dividend rate will allow the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield.

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Results of Operations
Three month periods ended MarchMonths Ended December 31, 2015 and 2014
The following table sets forth certain financial information with respect to our oil and natural gas operations:
Three Months Ended March 31,    Three Months Ended December 31,    
2015 2014 Variance Variance %2015 2014 Variance Variance %
Delhi field:       
Delhi field (see note below):       
Crude oil revenues$7,039,868
 $4,185,156
 $2,854,712
 68.2 %$6,558,215
 $7,644,831
 $(1,086,616) (14.2)%
Crude oil volumes (Bbl)147,621
 41,137
 106,484
 258.9 %165,654
 109,200
 56,454
 51.7 %
Average price per Bbl$47.69
 $101.74
 $(54.05) (53.1)%$39.59
 $70.01
 $(30.42) (43.5)%
              
Delhi field production costs$2,932,946
 $
 $2,932,946
  %$2,226,141
 $2,817,866
 $(591,725) (21.0)%
Delhi field production costs per BOE$19.87
 $
 $19.87
  %$13.44
 $25.80
 $(12.36) (47.9)%
              
Artificial lift technology:              
Crude oil revenues$12,695
 $95,031
 $(82,336) (86.6)%$7,589
 $42,039
 $(34,450) (81.9)%
NGL revenues1,352
 29,360
 (28,008) (95.4)%685
 11,028
 (10,343) (93.8)%
Natural gas revenues529
 26,661
 (26,132) (98.0)%317
 7,365
 (7,048) (95.7)%
Service revenues10,245
 
 10,245
  %56,121
 2,804
 53,317
 1,901.5 %
Total revenues$24,821
 $151,052
 $(126,231) (83.6)%$64,712
 $63,236
 $1,476
 2.3 %
              
Crude oil volumes (Bbl)285
 966
 (681) (70.5)%193
 563
 (370) (65.7)%
NGL volumes (Bbl)73
 756
 (683) (90.3)%42
 411
 (369) (89.8)%
Natural gas volumes (Mcf)204
 5,453
 (5,249) (96.3)%182
 2,413
 (2,231) (92.5)%
Equivalent volumes (BOE)392
 2,631
 (2,239) (85.1)%265
 1,376
 (1,111) (80.7)%
              
Crude oil price per Bbl$44.54
 $98.38
 $(53.84) (54.7)%$39.32
 $74.67
 $(35.35) (47.3)%
NGL price per Bbl18.52
 38.84
 (20.32) (52.3)%16.31
 26.83
 (10.52) (39.2)%
Natural gas price per Mcf$2.59
 4.89
 (2.30) (47.0)%$1.74
 3.05
 (1.31) (43.0)%
Equivalent price per BOE$37.18
 $57.41
 $(20.23) (35.2)%$32.42
 $43.92
 $(11.50) (26.2)%
              
Artificial lift production costs (a)$267,906
 $209,742
 $58,164
 27.7 %$53,731
 $191,553
 $(137,822) (71.9)%
Artificial lift production costs per BOE$683.43
 $79.72
 $603.71
 757.3 %$202.76
 $139.21
 $63.55
 45.7 %
              
Other properties:              
Revenues$
 $798
 $(798) (100.0)%
Equivalent volumes (BOE)
 26
 (26) (100.0)%
Equivalent price per BOE$
 $30.69
 $(30.69) (100.0)%
       
Production costs$639
 $143,887
 $(143,248) (99.6)%$
 $9,390
 $(9,390) (100.0)%
Production costs per BOE$
 $5,534.12
 $(5,534.12) (100.0)%
              
Combined:              
Oil and gas DD&A (b)$1,099,737
 $302,083
 $797,654
 264.1 %$1,254,350
 $701,543
 $552,807
 78.8 %
Oil and gas DD&A per BOE$7.43
 $6.90
 $0.53
 7.7 %$7.56
 $6.34
 $1.22
 19.2 %

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

(a) Includes workover costs of approximately $252,000$0 and $123,000,$134,000, for the three months ended MarchDecember 31, 2015 and 2014, respectively, that were primarily utilized to restore production in the Appelt #1H and Selected Lands #2 wells.respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $38,765$217,221 and $9,732,$216,214, for the three months ended MarchDecember 31, 2015 and 2014, respectively.



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Net Income Available to Common Stockholders.  For the three months ended MarchDecember 31, 2015, we generated net income to common shareholders of $0.6$0.7 million, or $0.02 per diluted share, on total revenues of $7.1$6.6 million. This compares to a net income of $.08$1.1 million, or $0.02$0.03 per diluted share, on total revenues of $4.3$7.7 million for the year-ago quarter.  The $0.2$0.4 million earnings decrease is primarily due to increased production costsresulted from a $1.1 million revenue decline and $1.5 million of higher operating expenses (which included a $1.3 million non-recurring restructuring charge), partially offset by higher revenues. The $0.8$1.7 million reduction achieved in generalof derivative gains and administrative expense was offset by an increase in non-cash DD&A expense. The components$0.5 million of netlower income are explained in greater detail below.taxes.
Delhi Field. Revenues increased 68%decreased 14% to $7.0$6.6 million as a result of a 259%43% decline in realized crude oil prices from $70.01 per barrel to $39.59 per barrel. This was partially offset by a 52% increase in production volumes from the year-ago quarter, primarily due towhich did not reflect a full quarter of production, as reversion of our working interest did not occur until 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.2014. Gross production of 6,2036,810 BOPD was essentially flat16% higher compared to the year-ago quarter.quarter as a result of production enhancement and conformance operations in the field. Production costs for the current quarter were $2.9$2.2 million, of which $1.6$1.0 million was for CO2 purchases and transportation expenses,costs, compared to no production$2.8 million, of which $1.7 million was for CO2 costs, in the year-ago quarter as those revenues were derived solely from our mineral and overriding royalty interests, which bore no operating expenses.quarter. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus sales taxes at 8% plus $0.20 per Mcf transportation costs. For the current quarter, total production costs were $27.60$13.44 per BOE on total production volumes. Production costs were $18.67 per BOE calculated solely on our working interest volumes, which includes $8.53 per working interest BOE, which includes $15.03 per BOE for CO2 purchase costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.

Artificial Lift Technology. Revenues of $0.1 million were virtually flat compared to the year-ago quarter. An increase in service revenue was offset by decreased 84%revenue from operated wells. Production volumes declined 81% to $25,000 reflecting a 85% volume decrease, primarily as a result of workovers on265 BOE and the Philip DL #1, Appelt #1H and Selected Lands #2 wells, together with a 35% decrease in the realized price per BOE from $57.41decreased 26% 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$32.42. Production costs decreased by approximately $0.1 million, as workover expenses on our operated 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 forlower than 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 $0.8increased $0.5 million, or 36%28%, to $1.5$2.1 million for the three months ended MarchDecember 31, 2015 from $2.3 million in the year-ago quarter, primarily due toprincipally as a result of $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,higher litigation costs, partially offset by $102,000 of higher legal expense, which reflected $0.3$0.1 million of lower accruals for short-term incentive compensation. Total litigation costs for the quarter were approximately $0.7 million.
Restructuring charge. We recognized a $1.3 million restructuring charge in the current quarter litigation costs.related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of the charge resulted from impairments of assets used in those operations and $0.7 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.

Other Income and Expenses. The Company realized gains of $1.3 million from derivatives that settled during the quarter and $0.4 million from the net change in unsettled derivative positions.
Depletion & Amortization Expense (“DD&A”).  DD&A increased $827,000,$0.6 million, or 265%60%, to $1.1$1.5 million for the current quarter compared to $312,000$0.9 million for the year-ago quarter, principally becauseprimarily as a result of $0.6 million of higher amortization of ourthe full cost oilpool. Production volumes increased 50% to 165,919 BOE and gas property cost pool. Full cost poolthe amortization rate increased 19% 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$7.56 per BOE ($7.43 in the current quarter versus $6.90 per BOE in the year-ago quarter).BOE. Compared to the year-ago quarter, the increased amortization rate was impacted by increased future development costs in the June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were lower as natural gas proved reservespreviously expected to be recoveredborne by the third party operator of the plant and decreases in reserves from the recycle stream byloss of the plannedPhilip DL #1 late in fiscal 2015 and from the decision to use produced methane at Delhi gas plant are now to be usedinternally to generate power forthereby lowering field operating costs rather than selling the Delhi field and not soldmethane 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.




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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,    Six Months Ended December 31, 
  
2015 2014 Variance Variance %2015 2014 Variance Variance %
Delhi field:       
Delhi field (see note below):       
Crude oil revenues$18,553,301
 $12,745,203
 $5,808,098
 45.6 %$13,854,601
 $11,513,433
 $2,341,168
 20.3 %
Crude oil volumes (Bbl)295,915
 124,089
 171,826
 138.5 %321,890
 148,294
 173,596
 117.1 %
Average price per Bbl$62.70
 $102.71
 $(40.01) (39.0)%$43.04
 $77.64
 $(34.60) (44.6)%
              
Delhi field production costs$5,750,812
 $
 $5,750,812
  %$4,784,028
 $2,817,866
 $1,966,162
 69.8 %
Delhi field production costs per BOE$19.43
 $
 $19.43
  %$14.86
 $19.00
 $(4.14) (21.8)%
              
Artificial lift technology:              
Crude oil revenues$129,714
 $340,230
 $(210,516) (61.9)%$37,016
 $117,019
 $(80,003) (68.4)%
NGL revenues34,607
 77,986
 (43,379) (55.6)%1,735
 33,255
 (31,520) (94.8)%
Natural gas revenues23,446
 64,821
 (41,375) (63.8)%1,021
 22,917
 (21,896) (95.5)%
Service revenues16,146
 
 16,146
  %107,960
 5,901
 102,059
 1,729.5 %
Total revenues$203,913
 $483,037
 $(279,124) (57.8)%$147,732
 $179,092
 $(31,360) (17.5)%
              
Crude oil volumes (Bbl)1,620
 3,383
 (1,763) (52.1)%873
 1,335
 (462) (34.6)%
NGL volumes (Bbl)1,228
 2,358
 (1,130) (47.9)%124
 1,155
 (1,031) (89.3)%
Natural gas volumes (Mcf)7,056
 17,932
 (10,876) (60.7)%489
 6,852
 (6,363) (92.9)%
Equivalent volumes (BOE)4,024
 8,730
 (4,706) (53.9)%1,078
 3,632
 (2,554) (70.3)%
              
Crude oil price per Bbl$80.07
 $100.57
 $(20.50) (20.4)%$42.40
 $87.65
 $(45.25) (51.6)%
NGL price per Bbl28.18
 33.07
 (4.89) (14.8)%13.99
 28.79
 (14.80) (51.4)%
Natural gas price per Mcf3.32
 3.61
 (0.29) (8.0)%2.09
 3.34
 (1.25) (37.4)%
Equivalent price per BOE$46.66
 $55.33
 $(8.67) (15.7)%$36.89
 $47.68
 $(10.79) (22.6)%
              
Artificial lift production costs (a)$656,819
 $526,712
 $130,107
 24.7 %$113,245
 $388,913
 $(275,668) (70.9)%
Artificial lift production costs per BOE$163.23
 $60.33
 $102.90
 170.6 %$105.05
 $107.08
 $(2.03) (1.9)%
              
Other properties:              
Revenues$20,369
 $134,754
 $(114,385) (84.9)%$
 $20,369
 $(20,369) (100.0)%
Equivalent volumes (BOE)285
 1,516
 (1,231) (81.2)%
 285
 (285) (100.0)%
Equivalent price per BOE$71.47
 $88.89
 $(17.42) (19.6)%$
 $71.47
 $(71.47) (100.0)%
              
Production costs$98,051
 $481,697
 $(383,646) (79.6)%$1,046
 $97,412
 $(96,366) (98.9)%
Production costs per BOE$344.04
 $317.74
 $26.30
 8.3 %n/a
 $341.80
 n/a
 n/a
              
Combined:              
Oil and gas DD&A (b)$2,061,440
 $922,781
 $1,138,659
 123.4 %$2,443,222
 $961,703
 $1,481,519
 154.1 %
Oil and gas DD&A per BOE$6.87
 $6.87
 $
  %$7.56
 $6.32
 $1.24
 19.6 %

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

(a) Includes workover costs of approximately $535,000$9,901 and $200,000,$283,000 for the ninesix months ended MarchDecember 31, 2015 and 2014, respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $364,169$246,622 and $25,875,$325,404 for the ninesix months ended MarchDecember 31, 2015 and 2014, respectively.

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Net Income Available to Common Stockholders.  For the ninesix months ended MarchDecember 31, 2015, we generated net income to common stockholdersshareholders of $2.6$3.6 million, or $0.08$0.11 per diluted share, on total revenues of $18.8$14.0 million. This compares to net income of $1.5$2.0 million, or $0.05$0.06 per diluted share, on total revenues of $13.4$11.7 million for the corresponding year-ago period.  AsThe $1.5 million earnings increase resulted from $2.3 million of higher revenue, was mostly offset by increased production costs due to much lower oil prices, the earnings increase is primarily due to expense decreases$3.5 million of $2.3derivative gains, and $1.1 million for G&A expense and $1.3 million for restructuring charges,from an insurance recovery, partially offset by $1.5$4.9 million of higher DD&A expense. Additional detailsoperating expenses (which include a $1.3 million non-recurring restructuring charge) and $0.5 million of the components of nethigher income are explained in greater detail below.taxes.
Delhi Field. Revenues increased 46%20% to $18.6$13.9 million as a result of a 139%117% increase in production volumes from the corresponding year-ago period, primarily due to the November 2014 reversion of our working interest, partially offset by a 39%45% decline in realized crude oil prices from $102.71$77.64 per barrel to $62.70$43.04 per barrel. The year-ago period did not include a full six months of net production, revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Gross production of decreased 3% to 5,9426,616 BOPD was 14% higher compared to 6,116 BOPD for the year-ago period.period as a result of production enhancement and conformance operations in the field. Production costs for the nine months ended March 31, 2015current period were $5.8$4.8 million, of which $3.3$2.4 million was for CO2 purchases and transportation expenses,costs, compared to no production$2.8 million, of which $1.7 million was for CO2 costs, in the corresponding year-ago period as those revenues were derived solely from our mineral and overriding royalty interests, which bear no operating expenses.period. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus sales tax at 8% plus $0.20 per Mcf transportation costs. Accordingly, such costs will be reduced inFor the future if oil prices remain at lower price levels. From our November 1, 2014 working interest reversion to Marchsix months ended December 31, 2015, total production costs were $32.80$14.86 per BOE on total production volumes. Production costs were $20.64 per BOE calculated solely on our working interest volumes, which includes $10.38 per working interest BOE which includesfor CO2 costs. These latter production costs of $18.66 per working interest BOE.BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.

Artificial Lift Technology. Revenues declined 18% to $0.1 million as a result of significantly lower revenue on our operated wells, offset by $0.1 million of higher GARP® service revenue. Production volumes decreased 58%70% to $204,000 reflecting a 54% volume decrease,1,078 BOE and the price per BOE decreased from $47.68 in the prior period to $36.89. Production costs declined by $0.3 million to $0.1 million, compared to $0.4 million in the prior period, primarily as a result of alower workover expenses on the Philip DL #1, together with a 16% decrease in the realized price per BOE, from $55.33 per barrel to $46.66 per barrel. We recorded $16,146 of service revenue from GARP® installations for a third-party customer. These wells did not contribute meaningful net profits to the Company in the nine months ended March 31, 2015. Artificial lift production costs were $657,000, which included $535,000 in workover costs, which were necessary in recovering proved reserves by restoring production in two key wellsour operated by us, the Appelt and the Selected Lands #2.wells.

Other Properties. The Company began divesting its non-core oil and gas properties in fiscal 2013, and revenues from these properties have correspondingly decreased to $20,000 compared to $135,000 in the corresponding year-ago period. The production costs from the year-ago period were high as a result of workover costs in South Texas and high water production in the Mississippi Lime. We completed our divestiture process in the prior quarter with the sale of the remaining interests in our Mississippi Lime properties.

General and Administrative Expenses (“G&A”).  G&A expenses decreased $2.3increased $0.6 million, or 33%,20% to $4.6$3.7 million duringfor the ninesix months ended MarchDecember 31, 2015 from $6.9 million in the corresponding year-ago period, primarily due to fiscal 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 costsprincipally as a result of our December 2013 restructuring,an $0.8 million increase in litigation costs and a $0.5$0.1 million declineincrease in accrued incentive compensation,salaries and payroll benefits, partially offset by $0.2$0.3 million of higher legal expense, impacted by $0.5lower accruals for short-term incentive compensation. Total litigation costs for the period were approximately $1.0 million.
Restructuring charge. Effective December 31, 2015, we recognized a $1.3 million restructuring charge related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of fiscal 2015 litigation costs. This fiscal 2014 restructuringthe charge consists of $1.3the impairment of assets used in that operation and $0.7 million consisted of $0.9was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of termination benefitsnon-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.
Other Income and $0.4Expenses. During the six months ended December 31, 2015, the Company realized gains of $2.2 million non-cash chargefrom derivatives that settled derivatives, $1.4 million for accelerated restricted stock vesting for terminated employees. See Note 7 - Restructuring.unsettled derivatives and $1.1 million from an insurance recovery at the Delhi field.

Depletion & Amortization Expense (“DD&A”).  DD&A increased $1.5$1.4 million, or 156%,109% to $2.4$2.7 million for the nine months ended March 31, 2015 from $0.9current period compared to $1.3 million for the corresponding year-ago period. Amortizationperiod as a result of our$1.5 million of higher amortization of the full cost oilpool, partially offset by lower depreciation on artificial lift technology equipment, miscellaneous fixed assets and gas property cost poolother assets. From the year-ago period production volumes increased 112% to 322,968 BOE and the amortization rate increased 20% to $7.56 per BOE. Compared to the year-ago period, the increased amortization rate was impacted by $1.1 million, or 123% primarily dueincreased future development costs in the June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were previously expected to higher volume generatedbe borne by the reversionary working interest. Forthird party operator of the nine months ended March 31, 2015, our rateplant and decreases in reserves from the loss of $6.87 per BOE was flat compared to the corresponding year-ago period. Depreciation expense for other property and equipment increased $338,000 principally due to depreciation of artificial lift equipment placedPhilip DL #1 late in service during fiscal 2015 and $273,000 of additional depreciation recognizingfrom the impairment of GARP® equipment installations on three wells of adecision to use produced methane at Delhi internally to generate power thereby lowering field operating costs rather than selling the methane to third party customer.customers.

Other Economic Factors

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

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party operated Delhi field have declined, and we believe such declines are attributable to improved operating efficiencies and generally lower third-party contractor and vendor expenses.  Product prices, operating costs and development costs may not always move in tandem.

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Known Trends and Uncertainties.  General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. We have recently seen significant declinesIf demand continues to decrease with a great oversupply in the future, it may continue to put downward pressure on crude oil and natural gas prices, and are uncertain if this downward price pressure will continue. If such lower crude oil prices persist,thereby lowering our revenues, andprofits, cash flow and working capital going forward will be adversely impacted.forward.

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

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

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Information about market risks for the three months ended MarchDecember 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.
2015.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 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 andWe use derivative instruments to manage our exposure to commodity price fluctuations. We presently do not hold or issue derivative instruments for hedging or speculative purposes.risk from time to time based on our assessment of such risk.

Interest Rate Risk
 
We currently have only a small exposure to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.  Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of MarchDecember 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.

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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 MarchDecember 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.

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PART II - OTHER INFORMATION
 
ITEM 1. LEGAL PROCEEDINGS
We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 1517Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 20142015 Annual Report. Material developments in the status of those proceedings during the quarter ended MarchDecember 31, 2015 are described in Part I. Item 1. "Financial Information" under Note 1516Commitments and Contingencies in this Quarterly Report.Report and incorporated herein by reference. We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position or on our results of operations.

ITEM 1A. RISK FACTORS
Our Annual Report on Form 10-K for the year ended June 30, 20142015 includes a detailed discussion of our risk factors. ThereIn addition to those, we add the following risk factor below:
We are materially dependent upon our operator with respect to the successful operation of our principal asset, which consists of our interests the Delhi Field. A materially negative change in our operator’s financial condition could negatively affect operations in the Delhi Field, and consequently our income from the field as well as the value of our interests in the Delhi Field.
Our royalty, mineral and working interests in the Delhi Field, located in Northeast Louisiana, are currently our most significant asset. Over 99% of our revenues come from these interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations and financial results. We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2- Enhanced Oil Recovery (“EOR”) project in the Delhi Field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been nocommitted by the operator. Additional capital remains to be invested to fully develop the EOR project, further increase production and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2- EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material changesadverse effect on us, and our results of operations and financial condition. 
Our economic success is thus materially dependent upon the Delhi Field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the risk factors previouslyfield and (iii) successfully manage related technical, operating, environmental, strategic and logistical risks, among other things. 
During the fall of 2014, the operator initiated work on expansion of the CO2 flood in the undeveloped eastern part of the field. These operations were suspended by the end of 2014 when the operator made significant cuts in its capital budget as a result of declining oil prices. While we believe that expansion remains economic at current commodity prices, resumption of this work could be electively delayed due to prevailing oil prices and the operator’s allocation of capital for such projects, negatively impacting us.
We are aware that the DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current level of indebtedness and the related financial covenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantial portion of DNR’s cash flow from operations to servicing their indebtedness. They noted that their ability to meet their obligations under their debt instruments will depend in part upon prevailing economic conditions and commodity prices. DNR also noted that it had deferred development spending for certain projects.
Given the current stress in the global commodity markets and oil & gas in particular, our Annual Report on Form 10-K foroperator could be materially negatively impacted, which could in turn negatively affect the year ended June 30, 2014.operator’s ability to operate the Delhi Field as well as it’s financial commitment to the EOR project in the field and thus our interests in the Delhi Field could be materially negatively impacted.

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

During the quarter ended MarchDecember 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 MarchDecember 31, 2015, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and/or exercises of stock options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting. In addition, during the quarter ended December 31, 2015, the Company repurchased shares of common stock in the open market under the previously announced share repurchase program. The table below summarizes information about the Company's purchases of its common stock during the quarter ended December 31, 2015.
Period 
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
Month of October 2015 none Not applicable Not applicable Not applicable
Month of November 2015 18,600 $6.37 Not applicable $3.4 million
Month of December 2015 10,928 $5.53 Not applicable $3.4 million

Period(1)
(a) Total NumberOn May 12, 2015, the Board of
Shares (or Units)
Purchased
(b) Average Price
Paid per Share (or
Units)
(c) Total Number Directors approved a share repurchase program covering up to $5 million 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
the Company's common stock. Under the Plansprogram's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or
Programs
discontinued at any time. Such shares were initially recorded as treasury stock, then subsequently canceled.
Month of January 2015(2)none___Not applicableNot applicable
Month of February 2015none___Not applicableNot applicable
Month of March 2015756During current quarter the Company received 2,001 shares of Common Stock$6.48Not applicableNot applicablecommon stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock. The acquisition cost per share reflected the weighted-average market price of the Company's shares at the dates vested.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

ITEM 5. OTHER INFORMATION
None.


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


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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 AccountingExecutive Officer
   
Date: MayFebruary 8, 20152016  


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