Table of Contents


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q
ý

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

For the quarterly period ended December 31, 20132014

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

For the transition period from          to          

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada

41-1781991

Nevada41-1781991
(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: xý 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: xý 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: xý

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of January 31, 2014,February 2, 2015, was 32,394,999.


32,860,087.


Table of Contents


EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

Page

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1





1

Table of Contents


PART I — FINANCIAL INFORMATION

ITEM 1. CONSOLIDATEDCONDENSEDFINANCIAL STATEMENTS


Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)

 

 

December 31,

 

June 30,

 

 

 

2013

 

2013

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

25,542,782

 

$

24,928,585

 

Certificate of deposit

 

 

250,000

 

Receivables

 

 

 

 

 

Oil and natural gas sales

 

1,497,561

 

1,632,853

 

Income taxes

 

281,970

 

281,970

 

Joint interest partner

 

2,368

 

49,063

 

Other

 

12,088

 

918

 

Deferred tax asset

 

26,133

 

26,133

 

Prepaid expenses and other current assets

 

633,980

 

266,554

 

Total current assets

 

27,996,882

 

27,436,076

 

 

 

 

 

 

 

Property and equipment, net of depreciation, depletion, and amortization Oil and natural gas properties — full-cost method of accounting, of which $4,258,459 and $4,112,704 at December 31, 2013 and June 30, 2013, respectively, were excluded from amortization

 

38,244,071

 

38,789,032

 

Other property and equipment

 

48,182

 

52,217

 

Total property and equipment

 

38,292,253

 

38,841,249

 

 

 

 

 

 

 

Advances to joint interest operating partner

 

43,646

 

26,059

 

Other assets

 

235,972

 

252,912

 

 

 

 

 

 

 

Total assets

 

$

66,568,753

 

$

66,556,296

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Accounts payable

 

$

325,294

 

$

642,018

 

Due to joint interest partner

 

86,289

 

127,081

 

Accrued compensation

 

743,804

 

1,385,494

 

Accrued restructuring charges

 

955,821

 

 

Royalties payable

 

139,553

 

91,427

 

Income taxes payable

 

 

233,548

 

Other current liabilities

 

537,114

 

153,182

 

Total current liabilities

 

2,787,875

 

2,632,750

 

 

 

 

 

 

 

Long term liabilities

 

 

 

 

 

Deferred income taxes

 

8,748,636

 

8,418,969

 

Asset retirement obligations

 

156,756

 

615,551

 

Deferred rent

 

44,293

 

52,865

 

 

 

 

 

 

 

Total liabilities

 

11,737,560

 

11,720,135

 

 

 

 

 

 

 

Commitments and contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at December 31, 2013, and June 30, 2013 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 32,062,186 shares at December 31, 2013, and 29,410,858 at June 30, 2013; outstanding 32,062,186 shares and 28,608,969 shares as of December 31, 2013 and June 30, 2013, respectively

 

32,062

 

29,410

 

Additional paid-in capital

 

33,264,497

 

31,813,239

 

Retained earnings

 

21,534,317

 

24,013,035

 

 

 

54,831,193

 

55,856,001

 

Treasury stock, at cost, no shares and 801,889 shares as of December 31, 2013 and June 30, 2013, respectively

 

 

(1,019,840

)

 

 

 

 

 

 

Total stockholders’ equity

 

54,831,193

 

54,836,161

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

66,568,753

 

$

66,556,296

 



 December 31,
2014
 June 30,
2014
Assets 
  
Current assets 
  
Cash and cash equivalents$22,523,164
 $23,940,514
Receivables2,924,570
 1,457,212
Deferred tax asset159,624
 159,624
Prepaid expenses and other current assets677,756
 747,453
Total current assets26,285,114
 26,304,803
Oil and natural gas property and equipment, net (full-cost method of accounting)38,536,733
 37,822,070
Other property and equipment, net333,001
 424,827
Total property and equipment38,869,734
 38,246,897
Other assets578,405
 464,052
Total assets$65,733,253
 $65,015,752
Liabilities and Stockholders’ Equity 
  
Current liabilities 
  
Accounts payable$4,821,014
 $441,722
State and federal income taxes payable45,392
 
Accrued liabilities and other811,821
 2,558,004
Total current liabilities5,678,227
 2,999,726
Long term liabilities 
  
Deferred income taxes10,553,861
 9,897,272
Asset retirement obligations727,124
 205,512
Deferred rent27,148
 35,720
Total liabilities16,986,360
 13,138,230
Commitments and contingencies (Note 15)

 

Stockholders’ equity 
  
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at December 31, 2014 and June 30, 2014 with a liquidation preference of $7,932,975 ($25.00 per share)317
 317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,860,087 shares and 32,615,646 as of December 31, 2014 and June 30, 2014, respectively32,860
 32,615
Additional paid-in capital36,035,076
 34,632,377
Retained earnings12,678,640
 17,212,213
Total stockholders’ equity48,746,893
 51,877,522
Total liabilities and stockholders’ equity$65,733,253
 $65,015,752

See accompanying notes to consolidated condensed financial statements.

2



2

Table of Contents


Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)

 

 

Three Months Ended

 

Six Months Ended

 

 

 

December 31,

 

December 31,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenues

 

 

 

 

 

 

 

 

 

Crude oil

 

$

4,344,765

 

$

5,379,399

 

$

8,936,142

 

$

9,384,821

 

Natural gas liquids

 

25,956

 

86,556

 

50,102

 

206,167

 

Natural gas

 

21,568

 

182,103

 

39,744

 

348,616

 

Total revenues

 

4,392,289

 

5,648,058

 

9,025,988

 

9,939,604

 

 

 

 

 

 

 

 

 

 

 

Operating Costs

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

223,498

 

419,328

 

633,345

 

735,497

 

Production taxes

 

13,032

 

20,863

 

21,435

 

42,236

 

Depreciation, depletion and amortization

 

327,168

 

350,119

 

636,841

 

647,036

 

Accretion of discount on asset retirement obligations

 

12,418

 

17,751

 

25,346

 

38,858

 

General and administrative expenses *

 

2,642,082

 

1,815,276

 

4,571,033

 

3,520,700

 

Restructuring charges**

 

1,332,186

 

 

1,332,186

 

 

Total operating costs

 

4,550,384

 

2,623,337

 

7,220,186

 

4,984,327

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from operations

 

(158,095

)

3,024,721

 

1,805,802

 

4,955,277

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

Interest income

 

7,701

 

5,614

 

15,404

 

11,230

 

Interest (expense)

 

(16,582

)

(16,564

)

(33,095

)

(32,992

)

 

 

(8,881

)

(10,950

)

(17,691

)

(21,762

)

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

(166,976

)

3,013,771

 

1,788,111

 

4,933,515

 

 

 

 

 

 

 

 

 

 

 

Income tax provision

 

241,907

 

1,054,499

 

724,543

 

1,814,717

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss)

 

$

(408,883

)

$

1,959,272

 

$

1,063,568

 

$

3,118,798

 

 

 

 

 

 

 

 

 

 

 

Dividends on Preferred Stock

 

168,576

 

168,576

 

337,151

 

337,151

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) available to common shareholders

 

$

(577,459

)

$

1,790,696

 

$

726,417

 

$

2,781,647

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.02

)

$

0.06

 

$

0.03

 

$

0.10

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

$

(0.02

)

$

0.06

 

$

0.02

 

$

 

0.09

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

30,063,676

 

28,071,317

 

29,335,498

 

28,032,223

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

30,063,676

 

31,856,417

 

32,377,918

 

31,836,983

 


 Three Months Ended 
 December 31,
 Six Months Ended 
 December 31,
 2014 2013 2014 2013
Revenues 
  
  
  
Delhi field$7,644,831
 $4,130,236
 $11,513,433
 $8,560,047
Artificial lift technology63,236
 189,894
 179,092
 331,985
Other properties
 72,159
 20,369
 133,956
Total revenues7,708,067
 4,392,289
 11,712,894
 9,025,988
Operating costs 
  
  
  
Production costs - Delhi Field2,817,866
 
 2,817,866
 
Production costs - artificial lift technology191,553
 153,221
 388,913
 316,970
Production costs - other properties9,390
 83,309
 97,412
 337,810
Depreciation, depletion and amortization917,757
 327,168
 1,287,107
 636,841
Accretion of discount on asset retirement obligations8,137
 12,418
 12,773
 25,346
General and administrative expenses *1,606,501
 2,642,082
 3,111,094
 4,571,033
Restructuring charges **(5,431) 1,332,186
 (5,431) 1,332,186
Total operating costs5,545,773
 4,550,384
 7,709,734
 7,220,186
Income (loss) from operations2,162,294
 (158,095) 4,003,160
 1,805,802
Other 
  
  
  
Interest income7,662
 7,701
 20,425
 15,404
Interest (expense)(12,159) (16,582) (30,619) (33,095)
Income (loss) before income taxes2,157,797
 (166,976) 3,992,966
 1,788,111
Income tax provision917,879
 241,907
 1,624,038
 724,543
Net income (loss) attributable to the Company$1,239,918
 $(408,883) $2,368,928
 $1,063,568
Dividends on preferred stock168,576
 168,576
 337,151
 337,151
Net income (loss) available to common stockholders$1,071,342
 $(577,459) $2,031,777
 $726,417
Earnings (loss) per common share       
Basic$0.03
 $(0.02) $0.06
 $0.03
Diluted$0.03
 $(0.02) $0.06
 $0.02
Weighted average number of common shares 
  
  
  
Basic32,825,631
 30,063,676
 32,754,016
 29,335,498
Diluted32,947,280
 30,063,676
 32,884,754
 32,377,918

* General and administrative expenses for the three months ended December 31, 20132014 and 20122013 included non-cash stock-based compensation expense of $316,422$245,020 and $393,579,$316,422, respectively. For the corresponding six month period’speriods, non-cash stock-based compensation expense was $488,357 and $689,860, and $747,369, respectively.


** Restructuring charges for the three months and six months ended December 31, 2013 included non-cash stock-based compensation expense of $376,365.

$376,365 and $376,365, respectively.


See accompanying notes to consolidated condensed financial statements.

3




3

Table of Contents


Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

 

 

Six Months Ended
December 31
,

 

 

 

2013

 

2012

 

Cash flows from operating activities

 

 

 

 

 

Net Income

 

$

1,063,568

 

$

3,118,798

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

657,265

 

667,461

 

Stock-based compensation

 

689,860

 

747,369

 

Stock-based compensation related to restructuring

 

376,365

 

 

Accretion of discount on asset retirement obligations

 

25,346

 

38,858

 

Settlements of asset retirement obligations

 

(57,247

)

(47,026

)

Deferred income taxes

 

329,667

 

1,498,760

 

Deferred rent

 

(8,574

)

(8,574

)

Changes in operating assets and liabilities:

 

 

 

 

 

Receivables from oil and natural gas sales

 

135,292

 

(797,933

)

Receivables from income taxes and other

 

(11,170

)

(116

)

Due to/from joint interest partner

 

4,687

 

40,050

 

Prepaid expenses and other current assets

 

(367,426

)

48,591

 

Accounts payable and accrued expenses

 

174,842

 

(390,979

)

Royalties payable

 

48,126

 

(74,876

)

Income taxes payable

 

(233,548

)

115,801

 

Net cash provided by operating activities

 

2,827,053

 

4,956,184

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Proceeds from asset sales

 

544,442

 

3,054,976

 

Capital expenditures for oil and natural gas properties

 

(856,943

)

(4,013,430

)

Capital expenditures for other property and equipment

 

(9,637

)

 

Other assets

 

(5,957

)

(26,110

)

Net cash used in investing activities

 

(328,095

)

(984,564

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Proceeds on exercise of incentive stock options

 

2,141,500

 

 

Cash dividends to preferred stockholders

 

(337,151

)

(337,151

)

Cash dividends to common stockholders

 

(3,205,135

)

 

Purchases of treasury stock

 

(1,127,801

)

(16,968

)

Windfall tax benefit

 

386,976

 

 

Maturity of certificate of deposit

 

250,000

 

 

Recovery of short swing profits

 

6,850

 

 

Deferred loan costs

 

 

(16,211

)

Net cash used in financing activities

 

(1,884,761

)

(370,330

)

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

614,197

 

3,601,290

 

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

24,928,585

 

14,428,548

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

25,542,782

 

$

18,029,838

 

4


 Six Months Ended 
 December 31,
 2014 2013
Cash flows from operating activities 
  
Net income attributable to the Company$2,368,928
 $1,063,568
Adjustments to reconcile net income to net cash provided by operating activities: 
  
Depreciation, depletion and amortization1,311,425
 657,265
Stock-based compensation488,357
 689,860
Stock-based compensation related to restructuring
 376,365
Accretion of discount on asset retirement obligations12,773
 25,346
Settlements of asset retirement obligations(220,522) (57,247)
Deferred income taxes656,589
 329,667
Deferred rent(8,574) (8,574)
Changes in operating assets and liabilities: 
  
Receivables from oil and natural gas sales(1,454,866) 135,292
Receivables from income taxes and other(12,492) (11,170)
Due from joint interest partner
 4,687
Prepaid expenses and other current assets69,697
 (367,426)
Accounts payable and accrued expenses1,384,201
 222,968
Income taxes payable45,392
 (233,548)
Net cash provided by operating activities4,640,908
 2,827,053
Cash flows from investing activities 
  
Proceeds from asset sales389,166
 544,442
Capital expenditures for oil and natural gas properties(1,136) (856,943)
Capital expenditures for other property and equipment(311,075) (9,637)
Other assets(84,341) (5,957)
Net cash used in investing activities(7,386) (328,095)
Cash flows from financing activities 
  
Proceeds on exercise of stock options51,600
 2,141,500
Cash dividends to preferred stockholders(337,151) (337,151)
Cash dividends to common stockholders(6,565,350) (3,205,135)
Acquisitions of treasury stock(58,660) (1,127,801)
Tax benefits related to stock-based compensation921,581
 386,976
Maturity of certificate of deposit
 250,000
Recovery of short swing profits(62,958) 
Deferred loan costs66
 6,850
Net cash used in financing activities(6,050,872) (1,884,761)
Net increase (decrease) in cash and cash equivalents(1,417,350) 614,197
Cash and cash equivalents, beginning of period23,940,514
 24,928,585
Cash and cash equivalents, end of period$22,523,164
 $25,542,782

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

Our supplemental disclosures of cash flow information for the six months ended December 31, 2013 and 2012 are as follows:

 

 

Six Months Ended

 

 

 

December 31,

 

 

 

2013

 

2012

 

Income taxes paid

 

$

755,564

 

$

200,156

 

 

 

 

 

 

 

Non-cash transactions:

 

 

 

 

 

Change in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties

 

(225,062

)

31,885

 

Change in due to joint interest partner used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties

 

1,216

 

(435,833

)

Oil and natural gas properties incurred through recognition of asset retirement obligations

 

48,988

 

8,558

 

Previously acquired Company shares swapped by holders to pay stock option exercise price

 

618,606

 

 

Supplemental disclosures of cash flow information:Six Months Ended 
 December 31,
 2014 2013
Income taxes paid$100,000
 $755,564
Non-cash transactions: 
  
Change in accounts payable used to acquire property and equipment1,410,420
 (223,846)
Oil and natural gas property costs incurred through recognition of asset retirement obligations562,482
 48,988
Previously acquired Company common shares swapped by holders to pay stock option exercise price
 618,606
See accompanying notes to consolidated condensed financial statements.

5



4

Table of Contents


Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statement of Changes in Stockholders’Stockholders' Equity

For the Six Months Ended December 31, 2013

2014

(Unaudited)

 

 

 

 

 

 

 

 

 

 

Additional

 

 

 

 

 

Total

 

 

 

Preferred

 

Common Stock

 

Paid-in

 

Retained

 

Treasury

 

Stockholders’

 

 

 

Shares

 

Par Value

 

Shares

 

Par Value

 

Capital

 

Earnings

 

Stock

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, June 30, 2013

 

317,319

 

$

317

 

28,608,969

 

$

29,410

 

$

31,813,239

 

$

24,013,035

 

$

(1,019,840

)

$

54,836,161

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation*

 

 

 

 

 

1,066,225

 

 

 

1,066,225

 

Exercise of stock options

 

 

 

2,726,911

 

2,727

 

2,757,380

 

 

 

2,760,107

 

Exercise of stock warrants

 

 

 

905,391

 

905

 

(905

)

 

 

 

Issuance of restricted stock

 

 

 

16,476

 

16

 

(16

)

 

 

 

Forfeitures of restricted stock

 

 

 

(51,099

)

(51

)

51

 

 

 

 

Purchases of treasury stock

 

 

 

(144,462

)

 

 

 

(1,746,407

)

(1,746,407

)

Retirements of treasury stock

 

 

 

 

(945

)

(2,765,302

)

 

2,766,247

 

 

Net income

 

 

 

 

 

 

1,063,568

 

 

1,063,568

 

Common Stock cash dividends

 

 

 

 

 

 

(3,205,135

)

 

(3,205,135

)

Preferred Stock cash dividends

 

 

 

 

 

 

(337,151

)

 

(337,151

)

Windfall tax benefit

 

 

 

 

 

386,975

 

 

 

386,975

 

Recovery of short swing profits

 

 

 

 

 

6,850

 

 

 

6,850

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2013

 

317,319

 

$

317

 

32,062,186

 

$

32,062

 

$

33,264,497

 

$

21,534,317

 

$

 

$

54,831,193

 



* Includes $376,365 of stock compensation reflected in restructuring charges.

 Preferred Common Stock        
 Additional
Paid-in
Capital
 Retained
Earnings
 Treasury
Stock
 Total
Stockholders'
Equity
 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
Issuance of restricted common stock
 
 213,466
 214
 (148) 
 
 66
Exercise of stock options
 
 37,000
 37
 51,563
 
 
 51,600
Acquisitions of treasury stock
 
 (6,025) 
 
 
 (58,660) (58,660)
Retirements of treasury stock
 
 
 (6) (58,654) 
 58,660
 
Stock-based compensation
 
 
 
 488,357
 
 
 488,357
Tax benefits related to stock-based compensation
 
 
 
 921,581
 
 
 921,581
Net income attributable to the Company
 
 
 
 
 2,368,928
 
 2,368,928
Common stock cash dividends
 
 
 
 
 (6,565,350) 
 (6,565,350)
Preferred stock cash dividends
 
 
 
 
 (337,151) 
 (337,151)
Balance, December 31, 2014317,319
 $317
 32,860,087
 $32,860
 $36,035,076
 $12,678,640
 $
 $48,746,893


See accompanying notes to consolidated condensed financial statements.

6




5

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





Note 1Organization and Basis of Preparation

Nature of Operations. Evolution Petroleum Corporation (“EPM”("EPM") and its subsidiaries (the “Company”"Company", “we”"we", “our”"our" or “us”"us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the exploitation, development of incremental oil and re-development ofgas reserves within known oil and gas resources for the production of crude oilour shareholders and natural gas,customers utilizing conventional specialized and proprietary technology to increase production, ultimate recoveries, or both.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 20132014 Annual Report on Form 10-K for the fiscal year ended June 30, 2013,2014, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries: NGS Sub Corp and its wholly owned subsidiary, Tertiaire Resources Company, Evolution Operating Co., Inc. Evolution Petroleum OK, Inc. and NGS Technologies, Inc. and its three wholly owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous period mayyear include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported lossnet income or stockholders’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.


7New Accounting Pronouncement. 

In June 2014, the FASB issued FASB Accounting Standards Update No. 2014-12 “Compensation-Stock Compensation (Topic 718) : Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period” (“ASU 2014-12”).


The amendments clarify the proper method of accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The update requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered.

The amendment in this update is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Management does not believe that any recently issued, but not yet effective accounting pronouncements, when adopted, will have a material effect on the accompanying financial statements.


6

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



Note 2 — Property and Equipment

Receivables


As of December 31, 20132014 and June 30, 20132014 our receivables consisted of the following:

 December 31,
2014
 June 30,
2014
Receivables from oil and gas sales$2,198,912
 $1,456,146
Receivable from suspended overriding royalty interest (a)712,100
 
Other13,558
 1,066
Receivables$2,924,570
 $1,457,212

(a) In connection with the lawsuit between the Company and Denbury Resources, Inc. ("Denbury") regarding the provisions of the May 8, 2006 Purchase and Sale Agreements, Denbury has unilaterally suspended payments related to 2.891545% of our overriding royalty interest ("ORRI") in the Delhi Holt Bryant Unit effective November 1, 2014. Accordingly, rather than remitting our usual 7.405201% ORRI and royalty payment, which Denbury has been paying the Company since 2006, Denbury arbitrarily applied a 2.891545% reduction for two months of ORRI by reducing their payment to the Company for December 2014 sales without the Company's consent. Such amounts are being held in suspense by Denbury pending resolution of the litigation. The Company's position is that Denbury has no legal basis for applying such a reduction and withholding our funds. [See Note 15 - Commitments and Contingencies.]


Note 3 — Prepaid Expenses and Other Current Assets

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

 December 31,
2014
 June 30,
2014
Prepaid insurance$155,827
 $169,288
Equipment inventory28,898
 85,888
Prepaid other34,320
 42,800
Retainers and deposits26,978
 29,478
Prepaid federal and Louisiana income taxes431,733
 419,999
Prepaid expenses and other current assets$677,756
 $747,453



Note 4 —Property and Equipment
As of December 31, 2014 and June 30, 2014 our oil and natural gas properties and other property and equipment consisted of the following:

 

 

December 31,
2013

 

June 30,
2013

 

Oil and natural gas properties

 

 

 

 

 

Property costs subject to amortization

 

$

42,746,486

 

$

42,772,184

 

Less: Accumulated depreciation, depletion, and amortization

 

(8,760,874

)

(8,095,856

)

Unproved properties not subject to amortization

 

4,258,459

 

4,112,704

 

Oil and natural gas properties, net

 

$

38,244,071

 

$

38,789,032

 

 

 

 

 

 

 

Other property and equipment

 

 

 

 

 

Furniture, fixtures and office equipment, at cost

 

332,151

 

322,514

 

Less: Accumulated depreciation

 

(283,969

)

(270,297

)

Other property and equipment, net

 

$

48,182

 

$

52,217

 

Unproved property not subject

 December 31,
2014
 June 30,
2014
Oil and natural gas properties 
  
Property costs subject to amortization$48,812,257
 $47,166,282
Less: Accumulated depreciation, depletion, and amortization(10,275,524) (9,344,212)
Oil and natural gas properties, net$38,536,733
 $37,822,070
Other property and equipment 
  
Furniture, fixtures and office equipment, at cost$286,820
 $343,178
Artificial lift technology equipment, at cost595,877
 377,943
Less: Accumulated depreciation(549,696) (296,294)
Other property and equipment, net$333,001
 $424,827

7

Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to amortization consists of unevaluated acreage of $4.2 million and $4.1 million as ofUnaudited Consolidated Condensed Financial Statements


During the six months ended ended December 31, 20132014, we incurred $217,934 of costs related to the installation of our artificial lift technology on the remaining two wells of a five-well program for a third-party customer. Under the contract for these installations, we fund the majority of the incremental equipment and June 30, 2013, respectively,installation costs and will receive 25% of the net profits from production, as defined, for our propertiesas long as the technology remains in the Mississippi Lime in Oklahoma.  Our evaluationwells. We are depreciating these costs using a method and a life which approximates the timing and amounts of impairment of unproved properties occurs, at a minimum, on a quarterly basis.our expected net revenues from the wells. During the six months ended December 31, 2013 and2014, we recorded additional depreciation of $267,326 to expense the corresponding 2012 period, no impairmentsunrecovered installation costs of artificial lift equipment, net of estimated residual salvage value, which have been recorded.

removed or are planned to be removed from three wells of a third-party customer.


Note 35 Joint Interest AgreementOther Assets

Effective April 17, 2012, a wholly owned subsidiary


As of December 31, 2014 and June 30, 2014 our other assets consisted of the Company entered into definitive agreementsfollowing:

 December 31,
2014
 June 30,
2014
Trademarks$43,333
 $40,928
Patent costs387,528
 305,592
Less: Accumulated amortization of patent costs(35,678) (27,050)
Deferred loan costs305,961
 243,003
Less: Accumulated amortization of deferred loan costs(122,739) (98,421)
Other assets, net$578,405
 $464,052


Note 6Accrued Liabilities and Other
As of December 31, 2014 and June 30, 2014 our other current liabilities consisted of the following:
 December 31,
2014
 June 30,
2014
Accrued incentive and other compensation$557,516
 $1,358,653
Accrued restructuring charges
 530,412
Officer retirement costs41,954
 288,258
Asset retirement obligations due within one year10,219
 146,703
Accrued royalties78,530
 89,179
Accrued franchise taxes74,414
 87,575
Other accrued liabilities49,188
 57,224
Accrued liabilities and other$811,821
 $2,558,004
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 Orion Exploration Partners, LLC (“Orion”) to acquire and develop interests inless emphasis on oil and gas leases, associated surface rightsoperations and related assets located ingreater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the Mississippian Lime formation in Kay County in North Central Oklahoma. Our participation in this joint venture is reflected on ourterminated 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, 2013 and June 30, 2013 balance sheets by2014.  Our disposition of the items below.accrued restructuring charges is as follows:


8

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

 

 

December 31,
2013

 

June 30,
2013

 

 

 

 

 

 

 

Advances to joint interest operating partner

 

$

43,646

 

$

26,059

 

Due to joint interest partner

 

86,289

 

127,081

 



Type of Cost
Balance at
December 31,
2013
 Payments Adjustment to Cost 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) $


Note 48Asset 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 are reconciliationsis a
reconciliation of the beginning and ending asset retirement obligation balances:

 

 

December 31,
2013

 

June 30,
2013

 

 

 

 

 

 

 

Asset retirement obligations — beginning of period

 

$

615,551

 

$

968,677

 

Liabilities sold

 

(48,273

)

(439,927

)

Liabilities incurred

 

 

60,143

 

Liabilities settled

 

(53,295

)

(51,086

)

Accretion of discount

 

25,346

 

72,312

 

Revision of previous estimates

 

48,988

 

5,432

 

Asset retirement obligations due within one year included in “Other current liabilities”

 

(431,561

)

 

Asset retirement obligations — end of period

 

$

156,756

 

$

615,551

 

8obligations for the six months ended December 31, 2014, and for the year ended June 30, 2014:

 December 31,
2014
 June 30,
2014
Asset retirement obligations — beginning of period$352,215
 $615,551
Liabilities sold(52,526) (48,273)
Liabilities incurred (a)562,485
 
Liabilities settled(137,604) (323,665)
Accretion of discount12,773
 41,626
Revision of previous estimates
 66,976
Less obligations due within one year(10,219) (146,703)
Asset retirement obligations — end of period$727,124
 $205,512
(a) Liabilities incurred during the period 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.



Table of Contents

Note 5 —9— Stockholders’ Equity


Common Stock

Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share. During the six months ended December 31, 2013 we issued (i) 1,008,657 shares of our common stock upon2014, the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $2.1 million,Company declared two quarterly dividends and (ii) 2,622,723 of our common shares upon cashless exercises of nonqualified stock options (NQSOs) and incentive warrants, all being exercised on a net basis, except for 50,956 of previously acquired shares owned by option holders that were swapped in payment of the exercise price.  The weighted average cost of these swapped shares was $12.14.

Additional paid-in capital increased $4.2 million, due to $1.1 million of stock compensation amortization ($0.4 million of which in the restructuring charge), $2.8 million from the exercise of stock options and warrants listed in (i) and (ii) above, and $0.4 million from tax benefits associated with stock compensation (i.e. windfall tax benefit).

Additional paid-in capital decreased by $2.8 million, due to the retirement of 801,889 shares of treasury stock acquired in previous fiscal years at a cost of approximately $1 million, and our purchase of 144,462 shares of Treasury Stock from employees and directors at a cost of $12.09 per share or $1.7 million.  93,506 of such shares were in satisfaction of payroll tax liabilities from exercises and restricted stock vestings (requiring cash outlays by us) and 50,956 shares were received from option holders in “swap” cashless stock option exercises, using stock previously owned by the option holder.  These acquisitions reduced the number of our common shares outstanding by 946,351 shares.

In December 2013 retained earnings were reduced by the $3.2 million of cash dividends we madepaid $6,565,350 to our common shareholders asshareholders. 



For the result of a common stock dividend policy approved bysix months ended December 31, 2014, the Board of Directors in November 2013.  Since we expectauthorized the windfall tax benefit created byissuance of 144,468 shares of restricted common stock from the recent exercise of warrants and NQSOs will drive our tax earnings and profits account into a deficit at June 30, 2014,2004 Stock Plan to all cash dividends on common shares paid in December 2013 will be treated for tax purposesemployees as a returnlong-term incentive award. In addition, the Board authorized the issuance of capital43,258 shares of restricted common stock to various employees for incentive compensation purposes and notissued 25,740 shares of restricted common stock as dividend incomecompensation to the shareholder.

Recovery of Stockholder Short Swing Profit

In September 2013, an executive officer of the Company paid $6,850 to the Company, representing the disgorgement of short swing profits under Section 16(b) under the Exchange Act. The amount was recorded as additional paid-in capital.

Company's directors. See Note 10 - Stock-Based Incentive Plan.


Series A Cumulative Perpetual Preferred Stock

At December 31, 2013,2014, there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding.  The Series A Cumulative Preferred Stock has a liquidation preference of $25.00 per share and cannot be converted into our common stock.  Therestock and there are no sinking fund or redemption rights available to the holders thereof. Optional redemption can only be made by us on or after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends, or earlier by an acquirer under a change of control at a redemption price of $25.25 per share.dividends.  With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common shareholders, 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

9

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


share, as, if and when declared by our Board of Directors.

During the six months ended December 31, 2013  weDirectors through its Dividend Committee. We paid dividends of $337,151 of cash dividendsand $337,151 to holders of our Series A Preferred Stock.  Since we expect the windfall tax benefit created by the recent exercise of warrants and NQSOs will drive our tax earnings and profits account into a deficit at June 30, 2014, cash dividends forStock during the six months ended December 31, 2014 and 2013, will berespectively.


Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2014, cash dividends on preferred and common stock were treated for tax purposes as a return of capital and notto our shareholders. Based on our current projections for the fiscal year ending June 30, 2015, we expect preferred 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 regarding the tax treatment of dividends for the current fiscal year when we report this information to recipients. As a result of the shareholder.

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 610—Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”"Stock Options"), restricted common stock awards (“("Restricted Stock”Stock"), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”"Plan"). Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorizedauthorizes the issuance of 6,500,000 shares of common stock.  No further shares are available for grant under the 2003 Stock Planstock and 784,438542,529 shares remain available for grant under the 2004 Stock Plan as of December 31, 2013.

9

2014.


Table of Contents

We have also granted common stock warrants, as authorized by the Board of Directors, to employees in lieu of cash bonuses or as incentive awards to reward previous service or provide incentives to individuals to acquire a proprietary interest in our success and to remain in our service (the “Incentive Warrants”).  These Incentive Warrants have similar characteristics of the Stock Options.  A total of 1,037,500 Incentive WarrantsOptions


No Stock Options have been issued, with Board of Directors approval, outside of the EPM Stock Plans.  We have not issued Incentive Warrantsgranted since the listing of our shares on the NYSE MKT (formerly, the American Stock Exchange) in July 2006.

Stock OptionsAugust 2008 and Incentive Warrants

For the six months ended December 31, 2013 and 2012, stock-based compensation expense was $- and $26,274, respectively.  As of August 31, 2012 all compensation costs attributable to Stock Options and Incentive Warrants had been recognized.

No Stock Options or Incentive Warrants have been granted since August 2008.

recognized in prior periods.


The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2013,2014, and the changes during the fiscal year:

 

 

Number of Stock
Options
and Incentive
Warrants

 

Weighted Average
Exercise Price

 

Aggregate
Intrinsic Value
(1)

 

Weighted
Average
Remaining
Contractual
Term (in
years)

 

 

 

 

 

 

 

 

 

 

 

Stock Options and Incentive Warrants outstanding at July 1, 2013

 

4,822,820

 

$

1.99

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercised

 

(4,069,815

)

$

1.99

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock Options and Incentive Warrants outstanding at December 31, 2013

 

753,005

 

$

2.01

 

$

7,778,744

 

2.0

 

 

 

 

 

 

 

 

 

 

 

Vested or expected to vest at December 31, 2013

 

753,005

 

$

2.01

 

$

7,778,744

 

2.0

 

 

 

 

 

 

 

 

 

 

 

Exercisable at December 31, 2013

 

753,005

 

$

2.01

 

$

7,778,744

 

2.0

 


 
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(37,000) 1.39
  
  
Stock Options outstanding at December 31, 2014141,061
 2.25
 $729,991
 1.3
Vested or expected to vest at December 31, 2014141,061
 2.25
 729,991
 1.3
Exercisable at December 31, 2014141,061
 $2.25
 $729,991
 1.3

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($12.347.43 as of December 31, 2013)2014) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock OptionsOptions.

Restricted Stock and Incentive Warrants.

There were 4,069,815Contingent Restricted Stock Options


Prior to August 28, 2014 all restricted stock grants contained a four-year vesting period based solely on service. Restricted stock which vests based solely on service is valued at the fair market value on the date of grant and Warrants exercised duringamortized over the six months ended December 31, 2013 with an aggregate intrinsic value of $41,247,805.

service period.


During the six months ended December 31, 2012 there2014, the Company awarded grants of both restricted stock and contingent restricted stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the restricted stock grants were 18,922 Stock Optionsissued on the date of grant, whereas the contingent restricted stock will be issued only upon the attainment of specified performance-based or market-based vesting provisions.


10

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


Performance-based grants vest upon the attainment of earnings, revenue and Incentive Warrantsother operational goals and require that vestedthe recipient remain an employee of the Company upon vesting. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the four year term. As of December 31, 2014, the Company does not consider the vesting of these performance-based grants to be probable and no compensation expense has been recognized.

Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting 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 these market-based awards ranged from $4.26 to $8.40 with a total grant dateexpected vesting periods of 3.30 to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of $46,359the awards at the date of grant and no unvested Stock Options and Incentive Warrants remained.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grantsis independent of vesting or expiration of the awards, except for the three months ended December 31, 2013 and 2012 was $316,422 and $393,579, respectively.  For the six months ended December 31, 2013 and 2012, such compensation expense was $689,860 and $747,369, respectively.  See Note 12 — Restructuring, for stock compensation included in Restructuring Charge for the six months ended December 31, 2013.

10



Tabletermination of Contents

service.


The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2013:

 

 

Number of
Restricted
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

 

 

 

 

 

 

Unvested at July 1, 2013

 

386,599

 

$

6.65

 

 

 

 

 

 

 

Granted

 

16,476

 

12.14

 

 

 

 

 

 

 

Vested

 

(142,404

)

$

6.21

 

 

 

 

 

 

 

Forfeited

 

(9,066

)

$

5.98

 

 

 

 

 

 

 

Unvested at December 31, 2013

 

251,605

 

$

7.28

 

At December 31, 2013, unrecognized stock2014:

 
Number of
Restricted
Shares
 
Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2014 (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(64,536) 8.59
    
Forfeited
 
    
Unvested at December 31, 2014288,997
 $9.23
 $1,749,848
 2.6

(1) Excludes $770,252 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 December 31, 2014 (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 December 31, 201456,286
 $8.20
 $68,507
 3.0
(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 totaled $1,359,862.  Such unrecognizedfor the three months ended December 31, 2014 and 2013 was $245,020 and $316,422, respectively. Stock-based compensation expense will be recognized over a weighted average period of 1.8 years.

11


related to Restricted Stock and Contingent Restricted Stock grants for the Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants six months ended December 31, 2014 and 2013 was $488,357 and $689,860, respectively. See Note 7 – Restructuring, for stock compensation included in Restructuring Charges for the six months ended December 31, 2013.

11

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




Note 711Fair Value Measurement


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


The three levels are defined as follows:


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


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


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


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


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


Note 8 12Income Taxes

We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

There were no FIN 48 unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the six months ended December 31, 2013.2014.  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, 20092010 through June 30, 2012.

2014.

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

Our estimated annual

We recognized income tax rate used to determine income tax expense of $1,624,038 and $724,543 for the six months ended December 31, 2013 does not include the utilization of statutory depletion deductions in excess of basis carried over from previous years that had driven our book tax rate well below statutory rates during the three months ended September 30, 2013.  Instead our tax benefits were changed significantly during November2014 and December 2013, when our employees, officers and directors exercised more than 4 million of 4.8 million stock options and incentive warrants, resulting in approximately $31.2 million of tax deductions (“Option Deductions”) available to us resulting in a tax impacted benefit of approximately $10.6 million assuming a 34% statutory rate.  On a financial reporting basis this is expected to result in a tax benefit associated with stock compensation (i.e. windfall tax benefit) to the extent of expected cash income taxes payable generated in fiscal year 2014.  The remainder of the Option Deductions result in an unbenefitted net operating loss associated with stock compensation to benefit future fiscal years.  To the extent the Option Deductions cause a net operating loss, no deferred tax asset is recorded under the rules of ASC 718.  The Option Deductions will be recorded as a reduction in current income taxes payable each year and an increase in equity to the extent cash taxes payable are reduced to zero. 

Because the Option Deductions are expected to reduce taxable income to zero for the year ended June 30, 2014, percentage depletion is no longer available for the current year, thus negating the beneficial rate reduction for the percentage depletion in excess of basis.  Percentage depletion that is no longer expected to be deductible in 2014, will be carried forward to future years.  The

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Table of Contents

Option Deductions will only impact reported earnings by increasing the projected effective tax rate closer to the statutory rate in those years affected by the Option Deductions due to percentage depletion in excess of basis deduction being delayed and carried forward.  Our effective annual tax rate estimated as December 31, 2013 was impacted by this postponement of depletion in excess of basis.  Our estimated annual income tax rate used to determine income tax expense for the three months ended September 30, 2013 included the utilization of statutory depletion deductions carried over from previous years resulting in a higher than normal rate benefit from depletion in excess of basis which has been reversed in the current fiscal quarter.

We recognized income tax expense of $724,543 and $1,814,717 for the six months ended December 31, 2013 and 2012, respectively, with corresponding effective rates of 41%40.7% and 37%40.5%.

13



12

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



Note 913Net Income (Loss) Per Share

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

 

 

Three Months Ended December 31,

 

Six Months Ended December 31,

 

 

 

2013

 

2012

 

2013

 

2012

 

Numerator

 

 

 

 

 

 

 

 

 

Net income available to common shareholders

 

$

(577,459

)

$

1,790,696

 

$

726,417

 

$

2,781,647

 

 

 

 

 

 

 

 

 

 

 

Denominator

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares — Basic

 

30,063,676

 

28,071,317

 

29,335,498

 

28,032,223

 

 

 

 

 

 

 

 

 

 

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

Common stock warrants issued in connection with equity and financing transactions

 

 

839

 

 

845

 

Stock Options and Incentive Warrants

 

 

3,784,261

 

3,042,420

 

3,803,915

 

Total weighted average dilutive securities

 

 

3,785,100

 

3,042,420

 

3,804,760

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares and dilutive potential common shares used in diluted EPS

 

30,063,676

 

31,856,417

 

32,377,918

 

31,836,983

 

 

 

 

 

 

 

 

 

 

 

Net income per common share — Basic

 

$

(0.02

)

$

0.06

 

$

0.03

 

$

0.10

 

Net income per common share — Diluted

 

$

(0.02

)

$

0.06

 

$

0.02

 

$

0.09

 

 Three Months Ended December 31, Six Months Ended December 31,
 2014 2013 2014 2013
Numerator 
  
  
  
Net income (loss) available to common shareholders$1,071,342
 $(577,459) $2,031,777
 $726,417
Denominator 
  
  
  
Weighted average number of common shares — Basic32,825,631
 30,063,676
 32,754,016
 29,335,498
Effect of dilutive securities: 
  
  
  
   Contingent restricted stock grants6,432
 
 1,785
 
   Stock options115,217
 
 128,953
 3,042,420
Weighted average number of common shares and dilutive potential common shares used in diluted EPS32,947,280
 30,063,676
 32,884,754
 32,377,918
        
Net income (loss) per common share — Basic$0.03
 $(0.02) $0.06
 $0.03
Net income (loss) per common share — Diluted$0.03
 $(0.02) $0.06
 $0.02
Outstanding potentially dilutive securities as of December 31, 2014 were as follows:
Outstanding Potential Dilutive Securities
Weighted
Average
Exercise Price
 
At
December 31,
2014
Contingent restricted stock grants
 56,286
Stock options$2.25
 141,061
 $1.61
 197,347
Outstanding potentially dilutive securities as of December 31, 2013 were as follows:

Outstanding Potential Dilutive Securities

 

Weighted
Average
Exercise Price

 

Outstanding at
December 31,
2013

 

 

 

 

 

 

 

Common stock warrants issued in connection with equity and financing transactions

 

$

 

 

Stock Options and Incentive Warrants

 

$

2.01

 

753,005

 

Total

 

$

2.01

 

753,005

 

Outstanding potentially dilutive securities as of December 31, 2012 were as follows:

Outstanding Potential Dilutive Securities

 

Weighted
Average
Exercise Price

 

Outstanding at
December 31,
2012

 

 

 

 

 

 

 

Common stock warrants issued in connection with equity and financing transactions

 

$

2.25

 

1,165

 

Stock Options and Incentive Warrants

 

$

1.82

 

5,342,820

 

Total

 

$

1.82

 

5,343,985

 

Outstanding Potential Dilutive Securities
Weighted
Average
Exercise Price
 At
December 31,
2013
Stock options$2.01
 753,005
Note 10 -14 — Unsecured Revolving Credit Agreement

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

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Table of Contents

The facility is unsecured and has a term of four year term.years, expiring on February 29, 2016.  Our subsidiaries guaranteedguarantee the Company’s obligations under the facility.  We may use the proceeds of any loans under the facility for the acquisition and development of Oiloil and Gas Properties (asgas properties, as defined in the facility),facility, the issuance of letters of credit, and for working capital and general corporate purposes.

Semi-annually, the Borrowing Baseborrowing base and a Monthly Reduction Amountmonthly reduction amount are re-determined from our reserve reports.  Requests by usthe 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 (as defined) of our Oiloil and Gas Properties.

gas properties, as defined.

At our option, borrowings under the facility bear interest at a rate of either (i) an adjustedAdjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rate or the sum of 0.50% and the Federal Funds Rate. A maximum of three LIBOR based loans can be outstanding at any time.  Allowed loan interest periods are one, two, three and six months.  LIBOR interest is payable at

13

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


the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term.  Base Rate interest is payable monthly.  Letters of credit bear fees reflecting 3.5% per annum rate applied to their principal amounts and are due when transacted.  TheirThe maximum term of letters of credit is one year.

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

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

As of December 31, 2013, we2014, 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 wereare in compliance with all the covenants of the Credit Agreement.

During May 2014, the Credit Agreement was amended to permit the payment of cash dividends on common stock if no borrowings are outstanding at the time of such payment.

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

The unamortized balance in debt issuance costs related to the Credit Agreement was $56,729 as of December 31, 2014. The Company is in discussions with the Lender to replace the unsecured Credit Agreement with an expanded secured facility. As of December 31, 2014, the Company had incurred approximately $126,493 in legal and title costs related to this proposed agreement, which are also capitalized in Other Assets.


Note 1115 — 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 jurisdictionjurisdictions in which we operate. At a minimum we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.  For

The Company and its wholly owned subsidiary 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 our wholly owned subsidiary 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 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.


14

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


As previously reported, on August 23, 2012, we and our wholly-owned subsidiary, NGS Sub Corp., and Robert S. Herlin, our Chief Executive Officer, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones (the “Jones lawsuit”) in the Western District Court of the Monroe Division, Louisiana. The plaintiffs allege primarily that we (defendants) wrongfully purchased the plaintiffs’ 0.048119 overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for EOR. The plaintiffs are seeking rescission of the assignment of the overriding royalty interest and monetary damages. We believe that the claims are without merit and are not timely, and we are vigorously defending against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the plaintiffs to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the plaintiffs' claims were valid on their face. On September 25, 2013, plaintiff Jones filed a motion to alter or amend the September 17, 2013 judgment. On December 27, 2013, the court denied said plaintiffs’ motion, and on January 21, 2014, we filed a motion to reconsider the nondismissal of the remaining claims, which was denied. The Court has entered a Scheduling Order setting trial of the case for the week of June 15, 2015. Counsel has advised us that, based on information developed to date, the risk of loss in this matter is remote.

On December 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi Field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims, including the assertion that we owed Denbury additional revenue interests pursuant to the 2006 agreements and that our transfer of the reversionary interests from our wholly owned subsidiary to our parent corporation and subsequently to another wholly-owned subsidiary were not timely noticed to Denbury. The Company disagrees with and is vigorously defending against Denbury's counterclaims.

On January 26, 2015, Denbury 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, is without legal proceedings, see “Part II, Item 1. Legal Proceedings.”

basis. Accordingly, the Company will continue to aggressively defend its property using all legal remedies and rights available to us. If we are required to forfeit some or all this disputed interest to Denbury, then our future reserves, value of reserves and revenues would be negatively impacted.


On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed Brooks' claims against NGS Sub Corp. We have denied and are vigorously defending all claims by Mr. Hawkins.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of December 31, 20132014 under this operating lease are as follows:

For the twelve months ended December 31,

 

 

 

2014

 

$

159,011

 

2015

 

159,011

 

2016

 

92,756

 

Total

 

$

410,778

 

For the twelve months ended December 31, 
2015$159,011
201692,756
Total$251,767
Rent expense for the three months ended December 31, 2014 and 2013 was $43,776 and 2012$44,759, respectively. Rent expense for the six months ended December 31, 2014 and 2013 was $44,759$87,551 and $36,808,$86,667, respectively.  For the corresponding six month periods of 2013 and 2012 rent expense was $86,667 and $73,617, respectively.

15



15

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



Employment Contracts.  We have entered into employment agreements with our three named executive officers.two of the Company's senior executives. The employment contracts provide for a severance package forpayments in the event of termination by usthe Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includesas defined. The agreements provide for the payment of base pay and certain medical and disability benefits for periods ranging from six months to aone year after termination.  The total contingent obligation under the employment contracts as of December 31, 20132014 is approximately $692,000.$473,000.

In connection with Sterling McDonald’s retirement announced in January 2014, we expect to pay Mr. McDonald a severance of $478,000 representing his base salary and anticipated bonus under our Cash Incentive Plan and $70,000 in other benefits.  In addition, we will accelerate the vesting of Mr. McDonald’s previously unvested restricted stock awards which will result in $220,500 of stock compensation expense to us.

Delhi Payout. We are presently in a dispute with the Delhi Field Operator concerning charges arising from the environmental event that began in June 2013.  We believe the Operator has indemnified us for such events, with the effect that payout should not be delayed.  To date, the Operator has not agreed to the application of the indemnity and their 2006 assumption of environmental liabilities.  Accordingly, we have filed a lawsuit against the Operator seeking declaration of the validity of the 2006 agreements, including the indemnity, and recovery of damages and attorney’s fees.

Note 12 — Restructuring

On November 1, 2013, we undertook an initiative refocusing our business on GARP® development that resulted in adjustment of our workforce towards less emphasis on engineering and greater emphasis on sales and marketing.  Accordingly, we accrued a restructuring charge in the second quarter ended December 31, 2013, based on agreements with terminated employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for non-compete clauses, incurring pre-tax cash and non-cash charges of approximately $1,332,000, of which $376,000 are non-cash charges related to accelerated stock compensation expenses. Our current estimates of accounting charges related to the initiative as of December 31, 2013 are as follows:

Type of Cost

 

December 31,
2013

 

 

 

 

 

Salary Expense

 

$

616,000

 

Cash Incentive Plan

 

186,000

 

Stock Compensation Expense

 

376,000

 

Other Benefits

 

154,000

 

Total Restructuring Charges

 

$

1,332,000

 

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, 20132014 (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 20132014 Annual Report on Form 10-K for the year ended June 30, 20132014 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.

16Corporation and its wholly owned subsidiaries.




Table of Contents

Executive Overview

General


We are engaged primarily in the exploitation, development of incremental oil and re-development ofgas reserves within known oil and gas resources for the production of crude oilour shareholders and natural gas,customers utilizing conventional specialized and proprietary technology to increase production, ultimate recoveries, or both.

technology. We are focused on increasing underlying net asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, includingand a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership ofin our common stock.


Our strategy is intended to generate scalable, low unit cost, development and re-development opportunities that minimize exploration risks.  These opportunities involvegrow the applicationvalue of modern technology, our ownDelhi asset to maximize the value realized by our shareholders while commercializing our patented GARP® artificial lift technology using the trade name of GARP®,for recovering incremental oil and our specific expertisegas reserves in overlooked areas of the United States.

The assets we exploit currently fit into two types of project opportunities:

·mature fields.Enhanced Oil Recovery (EOR), and

·Bypassed Primary Resources


We expect to fund our base fiscal 2014 development plan2015 capital program from working capital, with any increases to the base plan funded out of working capital and net cash flows from our properties.

Highlights for our Second Quarter Fiscal 20142015 and Project Update


“Q2-14”"Q2-15" & “current quarter”"current quarter" is the three months ended December 31, 2014, the company's 2nd quarter of fiscal 2015.

"Q1-15" & "prior quarter" is the three months ended September 30, 2014, the company's 1st quarter of fiscal 2015.

"Q2-14" & "year-ago quarter" is the three months ended December 31, 2013, the company’scompany's 2nd quarter of fiscal 2014.

“Q1-14” & “prior quarter” is the three months ended September 30, 2013, the company’s 1st quarter

Operations


16


“Q2-13” & “year-ago quarter” is the three months ended December 31, 2012, the company’s 2nd quarter of fiscal 2013.

Operations

·For Q2-14,Effective on November 1, 2014, the Company earned its 23.9% reversionary working interest and associated 19.036% net revenue interest in the Delhi Field. In addition to increased revenues, we are now paying our proportionate share of capital expenditures and lease operating expenses incurred going forward from November 1, 2014 in the field.


For Q2-15, the Company earned $1.1 million of net income, or $0.03 per diluted common share, a 286% increase from the year-ago quarter and a 12% increase from the prior quarter. The year-ago quarter had a net loss of $0.6 million primarily due to $2.1 million of one-time charges, compared to net income of $1.3 million in the prior quarternon-recurring expenses associated with a restructuring charge and $1.8 million in the year-ago quarter.expenses associated with derivative exercises and subsequent stock sale. The current quarter’s lossquarter income was due to a pre-tax $1.3 million restructuring charge, a $0.8 million non-recurring charge associated with the restructuringpositively affected by two months of increased net revenues from Delhi, offset by corresponding lease operating expenses and stock option exercises, higher GDD&A expense a higherfrom Delhi, along with increased estimated income tax expense, and lower revenues, partially offset by reduced LOE.expense.

·


Current quarter revenue decreased 5% sequentially to $4.4revenues were $7.7 million, from $4.6 million in the prior quarter and decreased 22% from $5.6 million in the year-ago quarter.  The sequential decline was due to lower Delhi crude oil prices offset by higher sales volumes from Delhi and from GARP® wells.  The decreasea 76% increase from the year-ago quarter is primarily due to lower Delhi revenue driven by both lower volumes and prices, as well as the absence of Giddings properties that were divested in late December 2012, offset by the addition of GARP® production.

·Black oil volumes accounted for 96% of total volumes and 99% of revenues during Q2-14, compared sequentially to 96% of volume and 99% of revenues in the prior quarter, while the year-ago quarter’s oil volume was 82% of volume and 95% of revenue.  Delhi oil volumes increased 6%a 93% increase from the prior quarter and decreased 9% compared to the year-ago quarter. The sequential increase in current quarter Delhi production reflects resumption of CO2 injection that had been previously curtailed due to the previously disclosed June 2013 environmental event.

·The blended oil, NGL and natural gas product price we received in Q2-14 decreased 12% sequentially to $93.66 per BOE from $106.17 in the prior quarter, and increased 6% from $88.23 in the year-ago quarter.  Current quarter oil prices decreased 12% sequentially to $96.70 and decreased 6% compared to the year-ago quarter.  Our average oil price reflects the large proportion of sales from Delhi that received favorable Louisiana Light Sweet pricing, although the price spread to WTI narrowed to 2% compared to the 10-20% premium experienced in prior periods. The LLS price premium in January 2014 has increased back to the ~10% level.  NGL price was flat sequentially and decreased 16% from the year-ago quarter to $30.64, while natural gas price increased 9% sequentially to $3.21 and was flat compared to the year-ago quarter.

17



Table of Contents

Projects — Core Assets

Delhi EOR Project

·Production in our Delhi enhanced oil recovery project increased 6% sequentially and decreased 9% from the year-ago quarter to 464 BOPD net to our 7.4% royalty interest (6,264 gross BOPD)The sequential increase was due in part to resumptiontwo months of CO2 injection in a portion of the field following the essential completion of the previously disclosed remediation of a fluids release in the field beginning in June 2013.  The decrease over the prior year is due to field response to development expenditures during 2012 that more than offset the effects of the temporary production impact of the remediation work during the second half of calendar 2013. The operator had temporarily suspended CO2 injection in the area surrounding the discovered fluid release in order to re-enter the previously plugged well(s) believed to be the source of the fluid release.  The reduction in CO2 injection that “drives” tertiary production temporarily reduced oil production in the area affected by the fluids release.

The temporary decline in production combinednet revenues associated with the remediation expense, net of any insurance reimbursements, is expected to delay the reversion of our 24% working interest to laterownership in 2014, excluding the effectDelhi field, partially offset by lower realized commodity prices in the quarter.


Delhi production averaged 1,187 net barrels of any indemnity of us by the operator.  To date, the operator has not agreed to the application of the indemnity and their 2006 assumption of environmental liabilities, and we have filedoil per day (“BOPD”), a lawsuit against the operator seeking declaration of the validity of the 2006 agreements, including the indemnity, and recovery of damages and attorney’s fees. The litigation asserts various breaches of the 2006 purchase and sale agreement between us and the operator including charging our payout account for the cost of their remediation work, failure to timely assign us our reversionary working interest due to unallowed charges to the deemed payout account, failure to indemnify us for reductions in production due to the environmental event in June 2013, charging our payout account $41.7 million through December 31, 2013 for the cost of the processing plant as an operating cost and not a capital cost, over $2.4 million of plugging and abandonment cost through December 31, 2013 charged as operating expense and not as capital, and failure to honor acquisitions made by the operator within the area of mutual interest.

Our working interest reversion, when it occurs as projected sometime in calendar 2014, will more than triple our revenue interest to more than 26.5%, while our cost bearing interest will156% increase from 0% to 23.9%.

·Realized oil prices at Delhi decreased 12% sequentially and decreased 7% from the year-ago quarter, and a 179% increase from the prior quarter. The sequential increase in volumes is due to the additional volumes associated with the working interest ownership in the Delhi field. Gross production in the field averaged 5,892 BOPD during the current quarter.


Realized crude oil prices received in Q2-15 decreased 28% to approximately $70 per barrel from $97 per BO.  Realized prices were $110 per BO in the previous quarter and $104 per BObarrel in the year-ago quarter, and decreased 29% from $99 per barrel in the prior quarter.

We remain debt-free, while distributing $3.3 million of cash dividends to our common stock shareholders during the current quarter.
Projects

·Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2014.
Delhi Field - Enhanced Oil Recovery Project

Gross production at Delhi in the second quarter of fiscal 2015 averaged 5,892 BOPD, a decrease of 6% from the year-ago quarter, and a 3% increase from prior quarter. Net production averaged 1,187 BOPD, a 156% increase from the year-ago quarter, and a 179% increase from the prior quarter. Gross production was impacted by the loss of one producing well due to down hole issues, and a replacement well has been redrilled and placed into production in January 2015. As a result of our working interest reversion taking effect on November 1, 2014, our total net revenue interest in the field has more than tripled from 7.41% to 26.44%, inclusive of all of our mineral interest ownership in Delhi. With the reversion, we now bear the corresponding working interest capital commitments to further develop the project and field, including necessary plugging and abandonment projects. In the quarter ending December 31, 2014, our net share of the joint interest billed capital expenditures was approximately $1.5 million and our net share of lease operating expenses was approximately $2.8 million, of which $1.7 million is related to CO2 purchases and CO2 transportation expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price per thousand cubic feet (“Mcf”) plus transportation costs of $0.20 per Mcf.

The operator of the Delhi field, a subsidiary of Denbury Resources, Inc. ("Denbury"), has stated its intentionthat the plans to install a gas plant to recover methane and natural gas liquids from the recyclerecycled gas stream targetingremains on their capital projects schedule with a target installation date of calendar year 2016.     

On January 26, 2015, Denbury 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, is without legal basis. Accordingly, the Company will continue to aggressively defend its property using all legal remedies and rights available to us. If we are required to forfeit some time in calendar 2015,or all this disputed interest to Denbury, then our future reserves, value of reserves and revenues would be negatively impacted.


17


GARP® - Artificial Lift Technology

During the current quarter, we completed the last of an earlier date than projected in our June 30, 2013 reserve report.  The operator has further stated its intention to delay significant further capital expenditures until our reversion has occurred. Proved oil reserves net to our interest are 74% developed and probable reserves are 48% developed asinitial five-well package of June 30, 2013, based on our independent engineer’s report as filed in our 2013 Form 10-K.GARP

GARP® (Gas Assisted Rod Pump)®

·Subsequent to the endinstallations for a third party operator. We have seen positive production responses from four of the quarter, we entered into an agreement withfive GARP® wells under this agreement. One well was not successful and the equipment was removed and used in a large independent operatorsubsequent installation. However, due to install GARP®operating costs, low commodity prices and a low net-back from gas processing under the customer’s pre-existing gas sales contract, our 25% net profits interest has resulted in ten wells inminimal service fee revenues to date. Given the Giddings Field.  The operator hascurrent low commodity price environment, the option to terminate the second five installations based on uneconomic performance in the first five installations. We will pay for the intangible costs of installationCompany and the operator will providehave mutually agreed to not proceed with the remaining five wells leasescontemplated by this contract, and most required tangible equipment. We will earnany future installations are expected to be subject to a fee equalnew fixed price agreement.


Artificial lift financial results continue to twenty-five percentbe adversely affected by unplanned workover expenses on our Company-operated wells, which temporarily suspended production for significant portions of the field cash profits from the wells. The operator has a substantial portfolio of similar candidates for installation of GARP® that could be added to our agreementcurrent quarter and substantially reduced GARP® revenues in the future.period.

·Our current commercialWe are presently working on two additional GARP® installations continue to perform as expected.

Projects — Non-Core Assets

Mississippi Lime

·We undertookpatents that will address the recompletion offollowing issues:

Wells with inadequate gas supply;
Solids settling on down-hole equipment;
Additional gas and solid separation.

In the Sneath well to plug off production frominterim, the first 2/3rds of the horizontal lateral that is lowest in section in order to test production from a structurally higher portion of the reservoir. GARP Production testing is underway. Unless we achieve more encouraging results, we do not currently contemplate further development of our leasehold this fiscal year.

18



Table of Contents

Lopez Field (South Texas) — Sold in December 2013

·® Effective December 1, 2013,marketing and business development efforts continue and include participation in oil field service and industry trade shows and one-on-one meetings with E&P operators of all sizes.

Other Properties
In October 2014, we completedclosed on the sale of all of our producingremaining mineral interests and assets and our undeveloped reserves in the Lopez Field.  HadMississippi Lime project for cash proceeds of approximately $389,000, net of customary closing adjustments. This transaction completes the divestment been completedprocess of divesting of all of our non-core oil and gas properties.

Liquidity and Capital Resources
We had $22.5 million and $23.9 million in cash and cash equivalents at the beginningDecember 31, 2014 and June 30, 2014, respectively. In addition, we have $5.0 million of the quarter, our production would have been reduced 7.0 BOE per day with  approximately $57,000 of revenue, $22,000 of direct well expense (using the company’s average $6.80/BOE depletion rate) and $25,000 of pre-tax well income ($39/BOE) would have been absent in the current quarter’s results.  Similarly, if the divestment had been completed July 1, 2013, approximately $117,000 of revenue, $189,000 of direct well expense (reflecting the company’s average $6.86/BOE depletion rate) and  $72,000 of pre-tax well loss ($58/BOE) would have been absent from our results foravailability under a revolving credit facility at period end.

During the six months ended December 31, 2013.

Restructuring

On November 1, 2013,2014, we undertook an initiative refocusingfinanced our operating resourcesoperations with cash generated from operations and cash on growinghand. At December 31, 2014, our working capital was $20.6 million, compared to working capital of $23.3 million at June 30, 2014.  The $2.7 million working capital decrease is primarily due to a $4.4 million increase in accounts payable reflecting post-reversion Delhi Field EOR project, commercialization of our GARP® patented artificial lift technologyoperating expenses and directly rewarding our common shareholders with continuing cash distributions.  Results during the current quarter include:

·Reduced our workforcecapital expenditures, partially offset by 27%, leading to a $1,332,000 pre-tax restructuring charge.  The charge includes 12 monthly installments of salary and benefit continuation, and immediate accelerated vesting of equity awards, for terminated employees in exchange for non-compete clauses.  Of the charge, $376,000 was non-cash expense related to accelerated stock compensation vesting.

·Recorded $0.8$1.8 million of one-time pre-tax charges arisinglower accrued liabilities principally attributable to incentive compensation, restructuring and officer retirement accrual declines.

Cash Flows from the exercises of 4 million of 4.8 million options, providing us $2.1 million of cash proceeds. The exercises were a reaction to our new dividend policy.  The charges included a 1% banking fee to orderly move 2.2 million exercised shares through the market to fund withholding tax liabilities and exercise costs, pay our $383,000 share of payroll tax liabilities associated thereto, and $168,000 in recruiting fees to replace Mr. McDonald.

·Going forward, approximately $1.4 million in recurring G&A expense will be reduced.  The adjustment of our workforce and one member reduction to our Board, will allow us to place greater emphasis on sales and marketing functions necessary for the full commercialization of GARP®.

·We began directly rewarding our common shareholders with a new dividend policy.  Our Board approved our first-ever cash dividend to common shareholders in the amount of $0.10 per share, payable December 27, 2013 to shareholders of record as of December 6, 2013, with the intention of further regular distributions consistent with expected improving cash flows at Delhi.

·Stock option exercises raised $2.1 million in cash proceeds, and will create approximately $10.6 million of future equity and permanent federal income tax savings on the next $31.2 million of otherwise taxable income at a 34% tax rate.  This “windfall tax benefit” temporarily displaces the percentage depletion in excess of basis deduction that has recently been lowering our book tax rate.  On a financial reporting basis, the “windfall tax benefit” will be recorded as a reduction in current income taxes payable each year and increase equity, to the extent cash taxes otherwise payable are reduced to zero.  Accordingly, our book tax rate has temporarily risen, since the “windfall” doesn’t run through the income statement under GAAP.

·Dividends distributions to preferred and common shareholders will be characterized as return of capital and not taxable dividends forOperating Activities

For the six months ended December 31, 2013.  The Option Deductions have driven our tax earnings and profits account into deficit, making2014, cash dividendsflows provided by operating activities were $4.6 million, which included a return of capital to the receiving shareholder.

See a full discussionvery slight impact from changes in “Note 8 — Income Taxes” to our financial statements.

Looking Forward

·~$0.7 million of cash proceeds from the exercise of ISO’s will be recorded in FQ3-14.  In January, Mr. McDonald cash exercised all 350,175 of his remaining ISO’s.

·There will be a ~$0.7 million one-time pretax charge to earnings in the quarter ending March 31, 2014.  As previously reported, Mr. McDonald will be provided that same benefits as the terminated employees.

·Long-term incentive awards normally paid in stock will be accrued as a cash “stay bonus” in this fiscal year.  Due to the restructure, the Board replaced the current year’s annual LTIP award payable in stock vesting over four years, with a “stay bonus” award for retained employees equal to one-fourth of the normal LTIP amount.  This will cause further reductions to stock-based compensation, with an offsetting increase in accrued bonus expense.

·Dividends paid to common and preferred shareholders through our year ending June 30, 2014 will be reported as return of capital and not as taxable dividends to the recipient.

Liquidity and Capital Resources

At December 31, 2013, ourother working capital was $25.2items.  Of the $4.6 million compared to working capital of $24.8provided, approximately $2.4 million at June 30, 2013.  The $0.4 million increase in working capital since June 30, 2013 was due primarily to $0.6net income, and approximately $2.2 million of increased cash, together with $0.4 of increased tax deposits, partially offset by decreased accounts receivable, and certificates of deposit partially offset by higher current liabilities.

19

was attributable to non-cash expenses.


Table of Contents

Cash Flows from Operating Activities

For the six months ended December 31, 2013, cash flows provided by operating activities were $2.8 million, reflecting $3.1 million provided by operations before $0.3 million was used by working capital. Of the $3.1 million provided before working capital changes, $1.1 million was due to net income, which reflects a $1.3 million restructuring charge, and $2.0$0.7 million was attributable to other non-cash expenses.

For

Cash Flows from Investing Activities
Investing activities for the six months ended December 31, 2012,2014 used $7,400 of cash, flows providedconsisting primarily of capital expenditures of approximately $311,000 for primarily artificial lift technology and $84,000 for GARP® patent costs, partially offset by operating activities were $5.0 million, reflecting $6.0 million provided by operations before $1.0 million was used$389,165 of proceeds received for the sale of properties in working capital. Of the $6.0 million provided before working capital changes, $3.1 million was due to net income and $2.9 million was due primarily to non-cash expenses.

Mississippi Lime project.


18


Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2013 was $0.9 million. Development activities were predominantly for GARP® installationsour GARP® wells in Giddings and additional testing in the Hendrickson well in the Mississippi Lime.Lime project. We received approximately $544,000$0.5 million of additional proceeds from asset sales, including $400,000$0.4 million for the recent salessale of our South Texas properties.


Cash paid for oil and gas capital expenditures duringFlows from Financing Activities
In the six months ended December 31, 2012 was $4.0 million. Development2014, we used $6.1 million in cash for financing activities were predominantly in the Mississippi Lime, where one salt water disposal wellprincipally consisting of cash outflows of $6.6 million for common stock dividend payments and two producer wells were completed. In Giddings, expenditures were centered on installing GARP® on a fourth commercial demonstration well. An inflow$0.3 million for preferred dividend payments, offset partially by $0.9 million of $3.1 million was received for proceeds from the sales of a portion of our Giddings exploration and production properties.

Oil and gas capital expenditures incurred, but not yet paid, were $0.5 million and $3.6 million, respectively, for the six months ended December 31, 2013 and 2012.  These amounts can be reconciledcash provided by tax benefits related to cash capital expenditures on their respective cash flow statements by adjusting them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

Cash Flows from Financing Activities

Instock-based compensation.


During the six months ended December 31, 2013, we used $1.9 million in cash for financing activities, including cash inflows of $2.1 million from stock option exercise proceeds and $0.4 million of windfall tax benefits, which was more than offset by cash outflows of $3.2 million for common dividends, $0.3 million for preferred dividends and $1.1 million for treasury stock purchases related to incentive stock warrant and stock option exercises and restricted stock vestings.

Capital Budget
Delhi Field
               With 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, we began funding our share of capital expenditures in the field. In the six monthsquarter ending December 31, 2014, our net share of the joint interest billed capital expenditures was approximately $1.5 million.

               Projected 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 million is for the gas processing plant and the balance is for continued development of the CO2 project. We expect these costs to be incurred over portions of the next two fiscal years, although these development plans are subject to review and deferral by either partner. Total spending based on proved reserves in the reserve report, net to our interest, is currently forecast to be approximately $45 million over the next four years, which includes the projects above plus further expansion of the CO2 flood patterns. We expect that cash flows from all our interests in the Delhi field will be in excess of the net capital expenditures required, subject to commodity prices that we realize.
GARP® - Artificial Lift Technology
Based on our current marketing and business plans, we expect that our capital requirements for artificial lift technology operations will be relatively minor over the next fiscal year.
Liquidity Outlook
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. As a result, our future revenues, cash flow, profitability, access to capital and future rate of growth is heavily influenced by the prices received for our production. Liquidity could also be affected by any adverse litigation outcome.
Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Our preference is to remain debt free, but we also 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, 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.
Payment of free cash flow in excess of our operating and capital requirements through cash dividends on 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 2015 and 2016 and Denbury's recent suspension of a portion of our overriding royalty interest revenues at Delhi, the Dividend Committee and the Board of Directors believes it is prudent to adjust the current dividend rate from $0.40 per share annually to $0.20 per share annually, effective in quarter ending March 31, 2015. The reduction in the dividend rate will allow the Company to conserve cash for additional financial flexibility to pursue opportunities while continuing to reward shareholders with a yield near 2.5% at current stock price levels.

19


Results of Operations
Three month periods ended December 31, 2012, we paid preferred dividends of $0.3 million, in addition to a minimal amount of treasury stock purchases2014 and deferred loan costs.

Capital Budget

We expect to fund all of our remaining fiscal 2014 Capital Plan, the total of which is uncertain at this time, with our $25.2 million of working capital on hand at December 31, 2013 and internally generated funds from operations. Our capital budget includes up to $17 million of development expenditures at Delhi, subject to the actual reversion date of our working interest and the rate at which calendar 2014 capital is expended there. Our GARP® business is expected to require approximately $1 million, depending upon expansion of the recent installation agreement and any other new agreement. No capital is currently allocated for further drilling in the Mississippian Lime assets.

20



Table of Contents

Results of Operations

Three month period ended December 31, 2013 and 2012

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

 

 

Three Months Ended

 

 

 

 

 

 

 

December 31,

 

 

 

%

 

 

 

2013

 

2012

 

Variance

 

Change

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

44,930

 

52,270

 

(7,340

)

(14.0

)%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

847

 

2,378

 

(1,531

)

(64.4

)%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

6,723

 

56,210

 

(49,487

)

(88.0

)%

Crude oil, NGLs and natural gas (BOE)

 

46,898

 

64,016

 

(17,118

)

(26.7

)%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

4,344,765

 

$

5,379,399

 

$

(1,034,634

)

(19.2

)%

 

 

 

 

 

 

 

 

 

 

NGLs

 

25,956

 

86,556

 

(60,600

)

(70.0

)%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

21,568

 

182,103

 

(160,535

)

(88.2

)%

Total revenues

 

$

4,392,289

 

$

5,648,058

 

$

(1,255,769

)

(22.2

)%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

96.70

 

$

102.92

 

$

(6.22

)

(6.0

)%

NGLs (per Bbl)

 

30.64

 

36.40

 

(5.76

)

(15.8

)%

Natural gas (per Mcf)

 

3.21

 

3.24

 

(0.03

)

(0.9

)%

Crude oil, NGLs and natural gas (per BOE)

 

$

93.66

 

$

88.23

 

$

5.43

 

6.2

%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

4.77

 

$

6.55

 

$

(1.78

)

(27.2

)%

Production taxes

 

$

0.28

 

$

0.33

 

$

(0.05

)

(15.2

)%

Depletion expense on oil and natural gas properties (a)

 

$

6.80

 

$

5.24

 

$

1.56

 

29.8

%


 Three Months Ended December 31,    
 2014 2013 Variance Variance %
Delhi field:       
Crude oil revenues$7,644,831
 $4,130,236
 $3,514,595
 85.1 %
Crude oil volumes (Bbl)109,200
 42,673
 66,527
 155.9 %
Average price per Bbl$70.01
 $96.79
 $(26.78) (27.7)%
        
  Delhi field production costs$2,817,866
 $
 $2,817,866
  
  Delhi field production costs per BOE$25.80
 $
 $25.80
  
        
Artificial lift technology:       
  Crude oil revenues$42,039
 $143,326
 $(101,287) (70.7)%
  NGL revenues11,028
 25,430
 (14,402) (56.6)%
  Natural gas revenues7,365
 21,138
 (13,773) (65.2)%
  Service revenue2,804
 
 2,804
  
  Total revenues$63,236
 $189,894
 $(126,658) (66.7)%
        
  Crude oil volumes (Bbl)563
 1,471
 (908) (61.7)%
  NGL volumes (Bbl)411
 834
 (423) (50.7)%
  Natural gas volumes (Mcf)2,413
 6,590
 (4,177) (63.4)%
  Equivalent volumes (BOE)1,376
 3,403
 (2,027) (59.6)%
        
  Crude oil price per Bbl$74.67
 $97.43
 $(22.76) (23.4)%
  NGL price per Bbl$26.83
 $30.49
 $(3.66) (12.0)%
  Natural gas price per Mcf$3.05
 $3.21
 $(0.16) (5.0)%
    Equivalent price per BOE$43.92
 $55.80
 $(11.88) (21.3)%
        
  Artificial lift production costs (a)$191,553
 $153,231
 $38,322
 25.0 %
  Artificial lift production costs per BOE$139.21
 $45.03
 $94.18
 209.1 %
        
Other properties:       
  Revenues$
 $72,159
 $(72,159) (100.0)%
  Equivalent volumes (BOE)
 822
 (822) (100.0)%
  Equivalent price per BOE$
 $87.78
 $(87.78) (100.0)%
        
  Production costs$9,390
 $83,309
 $(73,919) (88.7)%
  Production costs per BOE$
 $101.35
 $(101.35) (100.0)%
        
Combined:       
Oil and gas DD&A (b)$701,543
 $318,946
 $382,597
 120.0 %
Oil and gas DD&A per BOE$6.34
 $6.80
 $(0.46) (6.8)%

(a) Includes workover costs of approximately $134,000 and $35,000, for the three months ended December 31, 2014 and 2013, respectively.
(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $8,222$216,214 and $14,462,$8,222, for the three months ended December 31, 2014 and 2013, and 2012, respectively.




20


Net Income (Loss) Available to Common Shareholders.  For the three months ended December 31, 2013,2014, we incurred agenerated net lossincome to common shareholders of $577,459$1.1 million, or $0.02$0.03 per diluted share, (which includes a pre-tax non-cash $1.3 million restructuring charge, $0.8 million of non-recurring charges related to the restructuring and stock option exercises, and $316,422 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,392,289.$7.7 million. This compares to a net incomeloss of $1,790,696,$0.58 million, or $0.06$0.02 per diluted share, (which includes $393,579 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $5,648,058$4.4 million for the year-ago quarter.  IncreasedThe earnings increase is due to increased Delhi oil revenues weretogether with lower G&A and restructuring expenses, partially offset by Delhi production costs, higher operating expensesDD&A expense and higherincreased income tax reflecting a higher effective tax rate.expense.  Additional details of the components of net income are explained in greater detail below.

Sales Volumes.Delhi Field  Crude oil, NGLs, and natural gas sales. Revenues increased 85% to $7.6 million as a result of a 156% increase in production volumes net to our interest, for the three months ended December 31, 2013 decreased 27% to 46,898 BOE’s compared to 64,016 BOE’s forfrom the year-ago quarter.  This 17,118 volume decrease primarily reflects lower Giddings Field volumes, impactedquarter, partially offset by properties solda 28% decline in Fiscal 2013, together with a decrease in Delhi Field volumes. Ourrealized crude oil sales volumesprices from $96.79 per barrel to $70.01 per barrel. Lease operating expenses for the current quarter include 42,673 from our interestswere $2.8 million, of which $1.7 million is related to CO2 purchases and CO2 transportation expenses, compared to no production costs in Delhi and 2,257 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 46,815 barrelsas those revenues were derived solely from our mineral and overriding royalty interests, in Delhi and 5,455 barrels fromwhich bore no operating expenses. Under our propertiescontract with the operator, purchased CO2 is priced at 1% of the oil price per Mcf plus $0.20 per Mcf transportation costs. Accordingly, such costs will be reduced in the Giddingsfuture if oil prices remain at lower price levels.

Artificial Lift Technology. Revenues decreased 67% to $63,000 reflecting a 60% volume decrease, primarily as a result of workovers on the Philip DL #1 and Lopez fields.  Our NGL volumes for the three months ended December 31, 2013 declined 64% to 847 barrels compared to 2,378 barrelsSelected Lands #2 wells, together with a 21% decrease in the year-ago-quarter.  Current quarter natural gas volumes, virtually all produced at Giddings, decreased 88%realized price per BOE, from $55.80 to 6,723 mcf from 56,210 mcf in the year-ago quarter. At the end of$43.92 BOE. In the current quarter virtually allwe recorded $2,800 of Giddingsservice fee revenue from the GARP® installations for a third-party customer. These wells have not contributed meaningful net profits to the Company in the current quarter due to low commodity prices, poor netback contracts for gas processing and higher workover costs. Artificial lift production had been divested, except for our GARP® wells.

21



Table of Contents

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues decreased $1.3 million to $4.4 millioncosts were $192,000 for the current quarter, a 22% decrease25% increase from $5.6 million$153,000 in the year-ago quarter, due to a 27% volume decline, partially offset by a 6% higher price per BOE.  Prices per BOE were $93.66 and $88.23, respectively,include $134,000 in costs for the aforementioned workovers, which were necessary in recovering proved reserves.


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 $72,000 of revenues. The production costs from the prior year-ago quarter were high as a result of workover costs in South Texas and year-ago quarters.

Lease Operating Expenses (including ad valorem andhigh water production severance taxes).  Lease operating expenses and production taxes forin the Mississippi Lime project. With the sale of the remaining interests in our Mississippi Lime properties in the current quarter, decreased $203,661, or 46%, to $236,530 compared to the year-ago quarter.  Expenses were $41,000 lower at the Lopez Field, $44,000 lower at our Oklahoma properties, and declined $109,000 in the Giddings Field where the impact of Fiscal 2013 divestitures was partially offset by higher expenses at GARP® wells.  Lease operating expense and production tax per barrel of oil equivalent decreased 27% from $6.88 per BOE during year-ago quarter to $5.05 per BOE during current quarter.this divestiture process is now completed.


General and Administrative Expenses (“G&A”).  G&A expenses including $0.8decreased $1.0 million, of one-time charges, increased 46%or 39%, to $2.6$1.6 million during the three months ended December 31, 20132014 from $1.8$2.6 million in the year-ago quarter. Asquarter, primarily due to lower personnel-related costs as a result of the exercise of 4.0 million incentive warrantsour December 2013 restructuring and stock options during the current quarter, the Company incurred $251,000 of transactions fees and $383,500 additional payroll expense that impact respective variances below.  The $0.8 million increase was dueof one-time expenses primarily to $455,000associated with exercises of derivatives in higher salaries and benefits, $96,000 in higher bonus expense, and $40,000 increased business development, $180,000 higher transaction fees and $115,000 of increased consulting expensethe year-ago quarter partially offset by $77,000 of lower stock compensationrecent staff additions for accounting and $63,000 of lower legal expense.  Stock-based compensation was $316,422 (12% of total G&A) for the current quarter compared to $393,579 (22% of total G&A) for the year-ago quarter.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.GARP

Restructuring Charges®. We bookedIn addition, $1.3 million of restructuring expense was recorded in the currentyear-ago quarter primarily reflecting $0.9 million of termination benefits to be paid from January to December 2014 and a $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees. See Note 7 — Restructuring.


Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A decreased 6.6%increased $591,000, or 181% to $327,168$918,000 for the three months ended December 31, 2013,current quarter compared to $350,119$327,000 for the year-ago quarter. This change was principallyAmortization of our full cost oil and gas property cost pool increased by $383,000 on increased volumes of 136% due to reversionary working interest in Delhi field, offset by a 30% increaselower rate per BOE ($6.34 in depletion rate from $5.24the current quarter versus $6.80 per BOE in the year-ago quarterquarter). Depreciation expense for other property and equipment increased $208,000 principally due to $6.80 in$192,000 additional depreciation recorded during the current quarter partially offset by an 27% decline in volume as described above.  Muchto reflect the impairment of the higher depletion rate is due to higher future capital expenditures at Delhi associated with increased reserves reflected in our June 30, 2013 reserves report.GARP

® equipment installations on two wells of a third party customer.





21


Six month periodperiods ended December 31, 20132014 and 2012

2013

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

 

 

Six Months Ended
December 31,

 

 

 

%

 

 

 

2013

 

2012

 

Variance

 

Change

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

86,745

 

91,352

 

(4,607

)

(5.0

)%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

1,644

 

5,759

 

(4,115

)

(71.5

)%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

12,910

 

122,079

 

(109,169

)

(89.4

)%

Crude oil, NGLs and natural gas (BOE)

 

90,541

 

117,457

 

(26,916

)

(22.9

)%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

8,936,142

 

$

9,384,821

 

$

(448,679

)

(4.8

)%

 

 

 

 

 

 

 

 

 

 

NGLs

 

50,102

 

206,167

 

(156,065

)

(75.7

)%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

39,744

 

348,616

 

(308,872

)

(88.6

)%

Total revenues

 

$

9,025,988

 

$

9,939,604

 

$

(913,616

)

(9.2

)%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

103.02

 

$

102.73

 

$

0.29

 

0.3

%

NGLs (per Bbl)

 

30.48

 

35.80

 

(5.32

)

(14.9

)%

Natural gas (per Mcf)

 

3.08

 

2.86

 

0.22

 

7.7

%

Crude oil, NGLs and natural gas (per BOE)

 

$

99.69

 

$

84.62

 

$

15.07

 

17.8

%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

7.00

 

$

6.26

 

$

0.74

 

11.8

%

Production taxes

 

$

0.24

 

$

0.36

 

$

(0.12

)

(33.3

)%

Depletion expense on oil and natural gas properties (a)

 

$

6.86

 

$

5.28

 

$

1.58

 

29.9

%

22


 Six Months Ended December 31,    
 2014 2013 Variance Variance %
Delhi field:       
Crude oil revenues$11,513,433
 $8,560,047
 $2,953,386
 34.5 %
Crude oil volumes (Bbl)148,294
 82,952
 65,342
 78.8 %
Average price per Bbl$77.64
 $103.19
 $(25.55) (24.8)%
        
  Delhi field production costs$2,817,866
 $
 $2,817,866
  
  Delhi field production costs per BOE$19.00
 $
 $19.00
  
        
Artificial lift technology:       
  Crude oil revenues$117,019
 $245,199
 $(128,180) (52.3)%
  NGL revenues33,255
 48,626
 (15,371) (31.6)%
  Natural gas revenues22,917
 38,160
 (15,243) (39.9)%
  Service revenue5,901
 
 5,901
  
  Total revenues$179,092
 $331,985
 $(152,893) (46.1)%
        
  Crude oil volumes (Bbl)1,335
 2,417
 (1,082) (44.8)%
  NGL volumes (Bbl)1,155
 1,602
 (447) (27.9)%
  Natural gas volumes (Mcf)6,852
 12,479
 (5,627) (45.1)%
  Equivalent volumes (BOE)3,632
 6,099
 (2,467) (40.4)%
        
  Crude oil price per Bbl$87.65 $101.45 $(13.80) (13.6)%
  NGL price per Bbl$28.79 $30.35 $(1.56) (5.1)%
  Natural gas price per Mcf$3.34 $3.06 $0.28
 9.2 %
    Equivalent price per BOE$47.68 $54.43 $(6.75) (12.4)%
        
  Artificial lift production costs (a)$388,913
 $316,970
 $71,943
 22.7 %
  Artificial lift production costs per BOE$107.08
 $51.97
 $55.11
 106.0 %
        
Other properties:       
  Revenues$20,369
 $133,956
 $(113,587) (84.8)%
  Equivalent volumes (BOE)285
 1,490
 (1,205) (80.9)%
  Equivalent price per BOE$71.47
 $89.90
 $(18.43) (20.5)%
        
  Production costs$97,412
 $337,810
 $(240,398) (71.2)%
  Production costs per BOE$341.80
 $226.72
 $115.08
 50.8 %
        
Combined:       
Oil and gas DD&A (b)$961,703
 $620,698
 $341,005
 54.9 %
Oil and gas DD&A per BOE$6.32
 $6.86
 $(0.54) (7.9)%

Table(a) Includes workover costs of Contents

approximately $283,000 and $77,000, for the six months ended December 31, 2014 and 2013, respectively.

(a)(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $16,143$325,404 and $26,711$16,143, for the six months ended December 31, 2014 and 2013, and 2012, respectively.


22


Net Income Available to Common Shareholders.  For the six months ended December 31, 2013,2014, we generated net income to common shareholders of $726,417$2.0 million, or $0.06 per diluted share, on total revenues of $11.7 million. This compares to net income of $0.7 million, or $0.02 per diluted share, (which includes a $1.3 million non-cash restructuring charge, $0.8 million of non-recurring charges related to the restructuring and stock option exercises and $689,860 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $9,025,988.  This compares to a net income of $2,781,647, or $0.09 per diluted share, (which includes $747,369 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $9,939,604$9.0 million for the corresponding year-ago period.  The earnings declineincrease is primarily due to higher Delhi revenues together with lower revenueG&A and higher operating expense partiallyrestructuring expenses, offset by lowerDelhi production costs and increased DD&A and income taxes.tax expenses. Additional details of the components of net income are explained in greater detail below.

Sales Volumes.Delhi Field  Crude. Revenues increased 35% to $11.5 million as a result of a 79% increase in production volumes from the corresponding year-ago period, partially offset by a 25% decline in realized crude oil NGLs, and natural gas sales volumes, netprices, from $103.19 per barrel to our interest,$77.64 per barrel. Lease operating expenses for the six months ended December 31, 2013 decreased 23%2014 were $2.8 million, of which $1.7 million is related to 90,541 BOE’sCO2 purchases and CO2 transportation expenses, compared to 117,457 BOE’s for the year-ago period.  This 26,916 volume decrease primarily reflects the loss ofno production and sales volumes of properties soldcosts in Fiscal 2013, partially offset by increases in Delhi Field volumes and GARP® wells. Our crude oil sales volumes for the six months ended December 31, 2013 include 82,952 from our interests in Delhi and 3,793 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the corresponding year-ago period included 81,268 barrelsas those revenues were derived solely from our mineral and overriding royalty interests, in Delhi and 10,084 barrels fromwhich bear no operating expenses. Under our propertiescontract with the operator, purchased CO2 is priced at 1% of the oil price per Mcf plus $0.20 per Mcf transportation costs. Accordingly, such costs will be reduced in the Giddingsfuture if oil prices remain at lower price levels.

Artificial Lift Technology. Revenues decreased 46% to $179,000 reflecting a 40% volume decrease, primarily as a result of workovers on the Philip DL #1 and Lopez fields.  Our NGL volumes for the six months ended December 31, 2013 declined 72% to 1,644 barrels compared to 5,759 barrelsSelected Lands #2 wells, together with a 12% decrease in the year-ago period.  Current period natural gas volumes, virtually all produced at Giddings, decreased 89%realized price per BOE, from $54.43 per barrel to 12,910 mcf$47.68 per barrel. We recorded $2,800 of service revenue from 122,079 mcfGARP® installations for a third-party customer. These wells did not contribute meaningful net profits to the Company in the six months ended December 31, 2012.

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues decreased $0.9 million to $9.0 million2014. Artificial lift production costs were $389,000, which included $283,000 in costs for the six months ended December 31, 2013, a 9% decrease from $9.9 millionaforementioned workovers, which were necessary in the year-ago period due to a 23%volume decline partially offset by a 18% higher price per BOE.  Prices per BOE were $99.69recovering proved reserves.


Other Properties. The Company has been divesting its non-core oil and $84.62, respectively, for the six months ended December 31,gas properties since 2013, and 2012.

Lease Operating Expenses (including ad valorem and production severance taxes).  Lease operating expenses and production taxes for the six months ended December 31, 2013revenues from these properties have correspondingly decreased $122,953, or 16%, to $654,780$20,000 compared to $134,000 in the corresponding year-ago period. ExpensesThe production costs from the prior year were $54,000 higher at the Lopez Fieldhigh as a result primarily from workover costs in South Texas and $34,000 at our Oklahoma properties, but declined $190,000high water production in the Giddings Field due to divestituresMississippi Lime. With the sale of non-corethe remaining interests in our Mississippi Lime properties during Fiscal 2013, partially offset by higher expenses at GARP® wells.  Lease operating expense and production tax per barrel of oil equivalent increased 9% from $6.62 per BOE during year-ago period to $7.24 per BOE forin the six months ended December 31, 2013.current quarter, this divestiture process is completed.


General and Administrative Expenses (“G&A”).  G&A expenses including $0.8decreased $1.5 million, of one-time charges, increased 30%or 32%, to $4.6$3.1 million during the six months ended December 31, 20132014 from $3.5$4.6 million in the corresponding year-ago period.  Asperiod primarily due to $0.8 million of non-recurring year-ago quarter expense primarily related to stock option exercises, lower personnel-related costs as a result of the recent exercise of 4.0 million incentive warrants and stock options,  the Company incurred $251,000 of transactions fees and $383,500 additional payroll expense that impact respective variances below.  The $1.1 million increase was due primarily to $627,000 in higher salaries and benefits, $168,000 of higher transaction fees, $126,000 in higher bonus expense, and $69,000 increased business development, and $72,000 of increased management consulting expenseour December 2013 restructuring, partially offset by $64,000 of lower legal expenserecent staff additions for accounting and $57,000 decreased stock compensation expense.  Stock-based compensation was $689,860 (15% of total G&A) for the six months ended December 31, 2013 compared to $747,369 (21% of total G&A) for the corresponding year-ago period.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.GARP

Restructuring Charges®. The company bookedIn addition, $1.3 million of restructuring expense was recorded in December 2013the year-ago period primarily reflecting $0.9 million of termination benefits to be paid from January to December 2014 and a $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees. See Note 7 - Restructuring.


23



Table of Contents

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A decreased by 1.6%increased $650,000, or 102%, to $636,841$1.3 million for the six months ended December 31, 2013,2014 compared to $647,036$0.6 million for the corresponding year-ago period. This change wasAmortization of our full cost oil and gas property cost pool increased by $341,000 on 68% higher volumes due to the earning of our reversionary working interest in the Delhi field in November 2014, offset by a lower rate per BOE ($6.32 versus $6.86 per BOE in the year-ago period). Depreciation expense for other property and equipment increased $305,000 principally due to $268,000 additional depreciation recorded to reflect the impairment of GARP® equipment installations on three wells of a 30% increase in depletion rate from $5.28 per BOE a year ago to $6.86 in the current six-month period, partially offset by a 23% decline in volume as described above.  Much of the higher depletion rate is due to higher future capital expenditures at Delhi associated with increased reserves reflected in our June 30, 2013 reserves report.third party customer.


Other Economic Factors

Inflation.  Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services.  Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expensesproduction costs and our capital expenditures.  During fiscal 2013,2014, we saw modest increases in certain oil field services and materials compared to the prior fiscal year.  During fiscal 2014, these input costs were generally unchanged compared2015 to fiscal 2013.date, we have not seen material changes in costs.  Product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties.  General worldwide economic conditions continue to be uncertain and volatile.  Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas.  If demand decreasesWe have recently seen significant declines in the future, it may put downward pressure on crude oil prices and natural gasare uncertain if this downward price pressure will continue. If such lower crude oil prices thereby loweringpersist, our revenues and working capitalcash flow going forward.forward will be adversely impacted.  In addition, our lease operating expenses and their percentage of our revenues are likely to increase asthe reversion of our back-interest at Delhi or other additions to our working interest productionin the Delhi Field will increase both our revenues and lease operating expenses. This will reduce the extraordinary net margins that would dilute extraordinary margins we have enjoyedhistorically resulted from our mineral and overriding royalty interests at Delhi.  See “Note 12 -  Restructuring” within “ Item I. Financial Information.”


23



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


Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the quarter ending December 31, 2013.

242014.




Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended December 31, 2013,2014, did not change materially from the disclosures in Item 7A.7A of our Annual Report on Form 10-K for the year ended June 30, 2013 except as noted below.  As2014.
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 information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for our fiscal yearthree months ended June 30, 2013.

Interest Rate Risk

December 31, 2014. We are exposedexpect energy prices to changes in interest rates. Changes in interest rates affect the interest earned on our cashremain volatile and unpredictable. If energy prices decline further significantly, revenues and cash equivalents.  Underflow would significantly decline. In addition, a non-cash write-down of our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas.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. Lower prices may also reduce the amount of oil and natural gas that we can economically produce.  Although our current production base mayOur general philosophy is not be sufficient enough to effectively allow hedging, we may periodically use derivative instruments to hedge our commodity price risk. We mayIf 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 and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and natural gas sales when the associated production occurs. We presently do not hold or issue derivative instruments for hedging or speculative purposes.


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

ITEM 4. CONTROLS AND PROCEDURES

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

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 20132014 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended December 31, 20132014 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.


24


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 1415Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 20132014 Annual Report. During the quarter ended December 31, 2013, there were no materialMaterial developments in the status of those proceedings except asduring the quarter ended December 31, 2014 are described below.in Part I. Item 1. "Financial Information" under Note 15 — Commitments and Contingencies in this Quarterly Report. We believe that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on our financial position or on our results of operationsoperations.

25




Table of Contents

As previously reported, the Company and its wholly owned subsidiary are defendants in a lawsuit brought by John C. McCarthy et. al (the “plaintiffs”)  in the Fifth District Court of Richland Parish, Louisiana in July 2011.  The plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006. On March 29, 2012, the Fifth District Court dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp.  The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiff’s claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. 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 have again filed an appeal.

On October 14, 2013, a settlement agreement was executed in the lawsuit filed by Frederick M. Garcia and Lydia Garcia, et. al and the lawsuit was dismissed with prejudice on November 5, 2013.  As previously reported, on July 26, 2012, we agreed to settle a lawsuit filed by Frederick M. Garcia and Lydia Garcia in December 2010 in Duval County, Texas, in which the plaintiffs alleged failure to maintain the lease beyond its primary term due to no production. Although we believed that the claims were without merit, we chose to settle for $67,000 in return for an extension of the primary term of the lease, an amount less than our expected cost to prevail in court through summary judgment.

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

On December 13, 2013, we, and our wholly owned subsidiaries Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC alleging numerous breaches of certain 2006 agreements between the parties regarding the Delhi Field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined Area of Mutual Interest, breach of the promises to assume environmental liabilities and indemnify us from such costs, and other breaches. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees.

On December 3, 2013, our wholly owned subsidiary NGS Sub. Corp. was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks, a resident of Louisiana, alleging that a former subsidiary of NGS Sub. Corp. improperly disposed of off lease water in a well located on the plaintiff’s land in Winn Parish in 2006. NGS Sub. Corp. disposed of the property in question along with its ownership of the subsidiary in 2008 to a third party. We have denied the claims.

ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 20132014 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2013.

262014.



Table of Contents

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


During the quarter ended December 31, 2013,2014, the Company did not sell any equity securities that were not registered under the Securities Act.


Issuer Purchases of Equity Securities

During the quarter ended December 31, 2013,2014, the Company received shares of common stock from employees and directors of the Company for the cashless exercise of stock options and warrants, and to pay their share of payroll taxes arising from vestings of restricted stock andand/or exercises of stock options and warrants.options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting.

Period

 

(a) Total Number of
Shares (or Units)
Purchased

 

(b) Average Price
Paid per Share (or
Units)

 

(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs

 

(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs

 

 

 

 

 

 

 

 

 

 

 

October 1, 2013 to October 31, 2013

 

99 shares of Common Stock

 

$

11.26

 

Not applicable

 

Not applicable

 

November 1, 2013 to November 30, 2013

 

55,234 shares of Common Stock

 

$

12.14

 

Not applicable

 

Not applicable

 

December 1, 2013 to December 31, 2013

 

78,907 shares of Common Stock

 

$

12.13

 

Not applicable

 

Not applicable

 

27

Period 
(a) Total Number of
Shares (or Units)
Purchased
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
Month of October 2014 99 shares of Common Stock $9.17
 Not applicable Not applicable
Month of November 2014 none   Not applicable Not applicable
Month of December 2014 297 shares of Common Stock $7.75
 Not applicable Not applicable



Table of Contents

ITEM3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION
None.


25

None.

ITEM


ITEM 6. EXHIBITS

A.           Exhibits

31.1

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

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

32.1

Certification of Chief Executive Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) underto18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Securities ExchangeSarbanes-Oxley Act of 1934, as amended and 18 U.S.C. Section 1350.

2002.

32.2

32.2

Certification of Chief Financial Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended andto 18 U.S.C. Section 1350.

1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

99.1

Second Amendment to the Evolution Petroleum Corporation 2004 Amended and Restated Stock Plan

101.INS

XBRL Instance Document

101.SCH

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

28




26


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/ STERLING H. MCDONALD

Sterling H. McDonald

Vice-PresidentBy:

/s/ RANDALL D. KEYS
Randall D. Keys
President and Chief Financial Officer

Principal Financial Officer and

Principal Accounting Officer

Date: February 6, 2015

Date: February 7, 2014

29




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