UNITED STATES
(IRS Employer Identification No.) 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 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 $243,337 and $373,438, respectively. Six Months Ended 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 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 — information: September 30, 2014 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 technology.xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934December 31, 2013September 30, 2014Nevada41-1781991Nevada 41-1781991 (State or other jurisdiction of incorporation or organization) xý No: oxý No: oxýJanuary 31,November 4, 2014, was 32,394,999.Table of ContentsPagePage 67162525252526272828282829 September 30,
2014 June 30,
2014Assets Current assets Cash and cash equivalents $ 21,368,144 $ 23,940,514 Receivables Oil and natural gas sales 1,268,122 1,456,146 Other 23,524 1,066 Deferred tax asset 159,624 159,624 Prepaid expenses and other current assets 632,706 747,453 Total current assets 23,452,120 26,304,803 Oil and natural gas property and equipment, net (full-cost method of accounting) 37,651,450 37,822,070 Other property and equipment, net 444,942 424,827 Total property and equipment 38,096,392 38,246,897 Other assets 527,341 464,052 Total assets $ 62,075,853 $ 65,015,752 Liabilities and Stockholders’ Equity Current liabilities Accounts payable $ 611,547 $ 441,722 State and federal income taxes payable 44,173 — Accrued liabilities and other 874,013 2,558,004 Total current liabilities 1,529,733 2,999,726 Long term liabilities Deferred income taxes 10,021,875 9,897,272 Asset retirement obligations 209,028 205,512 Deferred rent 31,434 35,720 Total liabilities 11,792,070 13,138,230 Commitments and contingencies (Note 12) Stockholders’ equity Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares authorized, 317,319 shares issued and outstanding at September 30, 2014 and June 30, 2014 with a liquidation preference of $7,932,975 ($25.00 per share) 317 317 Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,797,743 shares and 32,615,646 as of September 30, 2014 and June 30, 2014, respectively 32,797 32,615 Additional paid-in capital 35,357,362 34,632,377 Retained earnings 14,893,307 17,212,213 Total stockholders’ equity 50,283,783 51,877,522 Total liabilities and stockholders’ equity $ 62,075,853 $ 65,015,752 Three Months Ended
September 30, 2014 2013 Revenues Delhi field $ 3,868,602 $ 4,429,811 Artificial lift technology 115,856 142,091 Other properties 20,369 61,797 Total revenues 4,004,827 4,633,699 Operating costs Production costs - artificial lift technology 197,360 163,749 Production costs - other properties 88,022 254,501 Depreciation, depletion and amortization 369,350 309,673 Accretion of discount on asset retirement obligations 4,636 12,928 General and administrative expenses * 1,504,593 1,928,951 Total operating costs 2,163,961 2,669,802 Income from operations 1,840,866 1,963,897 Other Interest income 12,763 7,703 Interest (expense) (18,460 ) (16,513 ) Net income before income taxes 1,835,169 1,955,087 Income tax provision 706,159 482,636 Net income attributable to the Company $ 1,129,010 $ 1,472,451 Dividends on preferred stock 168,575 168,575 Net income available to common stockholders $ 960,435 $ 1,303,876 Earnings per common share Basic $ 0.03 $ 0.05 Diluted $ 0.03 $ 0.04 Weighted average number of common shares Basic 32,682,401 28,607,320 Diluted 32,826,250 32,211,265 December 31, 2013September 30, 2014 and 2012 included non-cash stock-based compensation expense of $316,422 and $393,579, respectively. For the corresponding six month period’s non-cash stock-based compensation expense was $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.
December 31, Three Months Ended
September 30, 2014 2013 Cash flows from operating activities Net income attributable to the Company $ 1,129,010 $ 1,472,451 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 381,509 319,885 Stock-based compensation 243,337 373,438 Accretion of discount on asset retirement obligations 4,636 12,928 Settlements of asset retirement obligations (226,008 ) — Deferred income taxes 124,603 72,395 Deferred rent (4,286 ) (4,286 ) Changes in operating assets and liabilities: Receivables from oil and natural gas sales 188,024 11,133 Receivables from income taxes and other (22,458 ) 918 Due from joint interest partner — (14,614 ) Prepaid expenses and other current assets 114,747 53,948 Accounts payable and accrued expenses (1,345,875 ) (1,146,080 ) Income taxes payable 44,173 404,677 Net cash provided by operating activities 631,412 1,556,793 Cash flows from investing activities Proceeds from asset sales — 66,753 Capital expenditures for oil and natural gas properties (1,136 ) (594,214 ) Capital expenditures for other property and equipment (156,798 ) — Other assets (55,046 ) (1,913 ) Net cash used in investing activities (212,980 ) (529,374 ) Cash flows from financing activities Cash dividends to preferred stockholders (168,575 ) (168,575 ) Cash dividends to common stockholders (3,279,341 ) — Acquisitions of treasury stock (55,452 ) (117,182 ) Tax benefits related to stock-based compensation 537,282 — Recovery of short swing profits — 6,850 Deferred loan costs (24,716 ) — Net cash used in financing activities (2,990,802 ) (278,907 ) Net increase (decrease) in cash and cash equivalents (2,572,370 ) 748,512 Cash and cash equivalents, beginning of period 23,940,514 24,928,585 Cash and cash equivalents, end of period $ 21,368,144 $ 25,677,097 Evolution Petroleum Corporation and SubsidiariesConsolidated Condensed Statements of Cash Flows(Unaudited)Our supplementalSupplemental disclosures of cash flow information for the six months ended December 31, 2013 and 2012 are as follows: Three Months Ended
September 30, 2014 2013 Income taxes paid $ — $ — Non-cash transactions: Change in accounts payable used to acquire property and equipment (31,806 ) (136,436 ) Oil and natural gas property costs incurred through recognition of asset retirement obligations — 45,172 SixThree Months Ended December 31, 2013* 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, 2014 317,319 $ 317 32,615,646 $ 32,615 $ 34,632,377 $ 17,212,213 $ — $ 51,877,522 Issuance of restricted common stock — — 187,726 188 (188 ) — — — Acquisitions of treasury stock — — (5,629 ) — — — (55,452 ) (55,452 ) Retirements of treasury stock — — — (6 ) (55,446 ) — 55,452 — Stock-based compensation — — — — 243,337 — — 243,337 Tax benefits related to stock-based compensation — — — — 537,282 — — 537,282 Net income — — — — — 1,129,010 — 1,129,010 Common stock cash dividends — — — — — (3,279,341 ) — (3,279,341 ) Preferred stock cash dividends — — — — — (168,575 ) — (168,575 ) Balance, September 30, 2014 317,319 $ 317 32,797,743 $ 32,797 $ 35,357,362 $ 14,893,307 $ — $ 50,283,783 6Table of Contents(“EPM”("EPM") and its subsidiaries (the “Company”"Company", “we”"we", “our”"our" or “us”exploitation, development of incremental oil and re-development ofgas reserves within known oil and gas resourcesthe production of crude oilour shareholders and natural gas,customers utilizing conventional specialized and proprietary technology to increase production, ultimate recoveries, or both.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. 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 consolidatedperiod mayyear include certain reclassifications that were made to conform to the currentlossnet income or stockholders’stockholders' equity.7
Note 2 —Property and Equipment
|
| December 31, |
| June 30, |
| ||
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
| September 30, 2014 | June 30, 2014 | ||||||
| Oil and natural gas properties | |||||||
| Property costs subject to amortization | $ | 47,167,417 | $ | 47,166,282 | |||
| Less: Accumulated depreciation, depletion, and amortization | (9,515,967 | ) | (9,344,212 | ) | |||
| Oil and natural gas properties, net | $ | 37,651,450 | $ | 37,822,070 | |||
| Other property and equipment | |||||||
| Furniture, fixtures and office equipment, at cost | $ | 348,507 | $ | 343,178 | |||
| Artificial lift technology equipment, at cost | 497,606 | 377,943 | |||||
| Less: Accumulated depreciation | (401,171 | ) | (296,294 | ) | |||
| Other property and equipment, net | $ | 444,942 | $ | 424,827 | |||
| September 30, 2014 | June 30, 2014 | ||||||
| Accrued incentive and other compensation | $ | 323,318 | $ | 1,358,653 | |||
| Accrued restructuring charges | 175,307 | 530,412 | |||||
| Officer retirement costs | 116,289 | 288,258 | |||||
| Asset retirement obligations due within one year | 10,219 | 146,703 | |||||
| Accrued royalties | 77,376 | 89,179 | |||||
| Accrued franchise taxes | 113,027 | 87,575 | |||||
| Other accrued liabilities | 58,477 | 57,224 | |||||
| Accrued liabilities and other | $ | 874,013 | $ | 2,558,004 | |||
Note 3 — Joint Interest Agreement
Effective April 17, 2012, a wholly owned subsidiary2014. Our current estimate of the Company entered into definitive agreements with Orion Exploration Partners, LLC (“Orion”) to acquire and develop interests in oil and gas leases, associated surface rights and related assets located in the Mississippian Lime formation in Kay County in North Central Oklahoma. Our participation in this joint ventureremaining accrued restructuring charges as of September 30, 2014 is reflected on our December 31, 2013 and June 30, 2013 balance sheets by the items below.
|
| December 31, |
| June 30, |
| ||
|
|
|
|
|
| ||
Advances to joint interest operating partner |
| $ | 43,646 |
| $ | 26,059 |
|
Due to joint interest partner |
| 86,289 |
| 127,081 |
| ||
as follows:
| Type of Cost | Balance at December 31, 2013 | Payments | Adjustment to Cost | September 30, 2014 | |||||||||||
| Salary continuation liability | $ | 615,721 | $ | (461,790 | ) | $ | — | $ | 153,931 | ||||||
| Incentive compensation costs | 185,525 | (185,525 | ) | — | — | ||||||||||
| Other benefit costs and employer taxes | 154,575 | (94,199 | ) | (39,000 | ) | 21,376 | |||||||||
| Accrued restructuring charges | $ | 955,821 | $ | (741,514 | ) | $ | (39,000 | ) | $ | 175,307 | |||||
|
| December 31, |
| June 30, |
| ||
|
|
|
|
|
| ||
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 three months ended September 30, 2014, and for the year ended June 30, 2014:
| September 30, 2014 | June 30, 2014 | ||||||
| Asset retirement obligations — beginning of period | $ | 352,215 | $ | 615,551 | |||
| Liabilities sold | — | (48,273 | ) | ||||
| Liabilities incurred | — | — | |||||
| Liabilities settled | (137,604 | ) | (323,665 | ) | |||
| Accretion of discount | 4,636 | 41,626 | |||||
| Revision of previous estimates | — | 66,976 | |||||
| Less obligations due within one year | (10,219 | ) | (146,703 | ) | |||
| Asset retirement obligations — end of period | $ | 209,028 | $ | 205,512 | |||
During the six months ended
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 made to our common shareholders as the result of a common stock dividend policy approved by the Board of Directors in November 2013. Since we expectinitiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share. During 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 Junethree months ended September 30, 2014, we paid $3,279,341 of dividends to our common shareholders.
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.
various employees for incentive compensation purposes. See Note 7 - Stock-Based Incentive Plan.
During the six months ended December 31, 2013 weDirectors through its Dividend Committee. We paid $337,151dividends of cash dividends$168,575 and $168,575 to holders of our Series A Preferred Stock. Since we expectStock during the windfall tax benefit created bythree months ended September 30, 2014 and 2013, respectively.
recipients.
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
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.
|
| Number of Stock |
| Weighted Average |
| Aggregate |
| Weighted |
| ||
|
|
|
|
|
|
|
|
|
| ||
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, 2014 | 178,061 | $ | 2.08 | |||||||||
| Stock Options outstanding at September 30, 2014 | 178,061 | $ | 2.08 | $ | 1,264,907 | 1.5 | ||||||
| Vested or expected to vest at September 30, 2014 | 178,061 | $ | 2.08 | $ | 1,264,907 | 1.5 | ||||||
| Exercisable at September 30, 2014 | 178,061 | $ | 2.08 | $ | 1,264,907 | 1.5 | ||||||
There were 4,069,815 Stock Options and Warrants exercised during the six months ended December 31, 2013 with an aggregate intrinsic value of $41,247,805.
During the six months ended December 31, 2012 there were 18,922 Stock Options and Incentive Warrants that vested with a total grant date fair value of $46,359 and no unvested Stock Options and Incentive Warrants remained.
Restricted Stock
Stock-based compensation expense related to Options.
service.
|
| Number of |
| Weighted |
| |
|
|
|
|
|
| |
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 stockSeptember 30, 2014:
Number of Restricted Shares | Weighted Average Grant-Date Fair Value | Unamortized Compensation Expense at September 30, 2014 (1) | Weighted Average Remaining Amortization Period (Years) | |||||||||
| Unvested at July 1, 2014 | 140,067 | $ | 8.70 | |||||||||
| Service-based shares granted | 75,170 | 10.13 | ||||||||||
| Performance-based shares granted | 76,642 | 10.05 | ||||||||||
| Market-based shares granted | 35,914 | 7.59 | ||||||||||
| Vested | (21,873 | ) | 6.86 | |||||||||
| Unvested at September 30, 2014 | 305,920 | $ | 9.39 | $ | 1,789,833 | 2.9 | ||||||
| Number of Restricted Stock Units | Weighted Average Grant-Date Fair Value | Unamortized Compensation Expense at September 30, 2014 (1) | Weighted Average Remaining Amortization Period (Years) | |||||||||
| Unvested at July 1, 2014 | — | $ | — | |||||||||
| Performance-based awards granted | 38,325 | 10.05 | ||||||||||
| Market-based awards granted | 17,961 | 4.26 | ||||||||||
| Unvested at September 30, 2014 | 56,286 | $ | 8.20 | $ | 74,502 | 3.2 | ||||||
11for the three months ended September 30, 2014 and 2013 was $243,337 and $373,438, respectively.
Note 78—Fair Value Measurement
2014.
Our estimated annual income tax rate used to determine
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
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$482,636 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 $724,5432014 and $1,814,717 for the six months ended December 31, 2013, and 2012, respectively, with corresponding effective rates of 41%38.5% and 37%24.7%.
13
Note 910 —Net Income Per Share
|
| Three Months Ended December 31, |
| Six Months Ended December 31, |
| ||||||||
|
| 2013 |
| 2012 |
| 2013 |
| 2012 |
| ||||
Numerator |
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Net income available to common shareholders |
| $ | (577,459 | ) | $ | 1,790,696 |
| $ | 726,417 |
| $ | 2,781,647 |
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Denominator |
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Weighted average number of common shares — Basic |
| 30,063,676 |
| 28,071,317 |
| 29,335,498 |
| 28,032,223 |
| ||||
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Effect of dilutive securities: |
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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 |
| ||||
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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 |
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| ||||
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 September 30, | ||||||||
| 2014 | 2013 | |||||||
| Numerator | ||||||||
| Net income available to common shareholders | $ | 960,435 | $ | 1,303,876 | ||||
| Denominator | ||||||||
| Weighted average number of common shares — Basic | 32,682,401 | 28,607,320 | ||||||
| Effect of dilutive securities: | ||||||||
| Weighted average of contingent restricted stock grants | 1,552 | — | ||||||
| Weighted average of stock options | 142,297 | 3,603,945 | ||||||
| Weighted average number of common shares and dilutive potential common shares used in diluted EPS | 32,826,250 | 32,211,265 | ||||||
| Net income per common share — Basic | $ | 0.03 | $ | 0.05 | ||||
| Net income per common share — Diluted | $ | 0.03 | $ | 0.04 | ||||
Outstanding Potential Dilutive Securities |
| Weighted |
| Outstanding at |
| |
|
|
|
|
|
| |
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 Potential Dilutive Securities | Weighted Average Exercise Price | At September 30, 2014 | ||||
| Contingent restricted stock grants | $ | — | 56,286 | |||
| Stock options | $ | 2.08 | 178,061 | |||
| $ | 1.58 | 234,347 | ||||
Outstanding Potential Dilutive Securities |
| Weighted |
| Outstanding at |
| |
|
|
|
|
|
| |
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 September 30, 2013 | ||||
| Stock options | $ | 1.99 | 4,822,820 | |||
The facility is unsecured and has a term of four gas properties, as defined. 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. The unamortized balance in debt For the twelve months ended December 31, 2014 $ 159,011 2015 159,011 2016 92,756 Total $ 410,778 Employment Contracts. We have entered into employment agreements with technology. We are focused on increasing underlying mature fields. substantially reduced GARP® Cash Flows from Operating Activities stock-based compensation. 19.1% net revenue interest in Delhi occurred effective November 1, 2014, we will begin funding our share of capital and operating expenditures in the Field. Projected capital expenditures over the next two fiscal years are currently expected to total approximately $25-27 million net to our working interest. The timing of this spending is dependent on the pace of project development by the operator of the Field. Of this total, approximately $15-17 million is for the gas processing plant and approximately $10 million is for the roll-out of the next phase of the CO project. We expect these costs to 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 % Note: There were three producing wells in the period ending 2014 versus four in the period ending 2013. General and Administrative Expenses (“G&A”). G&A expenses Six Months Ended % 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 %1011 - Unsecured Revolving Credit Agreementyear term.years. Our subsidiaries guaranteed 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.Borrowing Baseborrowing base and a Monthly Reduction Amountmonthly reduction amount are re-determined from 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.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 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.for compensating the Lender $50,000 for incurredin loan costs incurred upon closing.December 31, 2013, weSeptember 30, 2014, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000, and we wereare in compliance with all the covenants of the1112 — Commitments and Contingenciesjurisdictionjurisdictions 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 legal proceedings, see “Part II, Item 1. Legal Proceedings.”December 31, 2013September 30, 2014 under this operating lease are as follows:For the twelve months ended September 30, 2015 $ 159,011 2016 132,509 Total $ 291,520 December 31,September 30, 2014 and 2013 was $43,776 and 2012 was $44,759 and $36,808,$41,918, respectively. For the corresponding six month periods of 2013 and 2012 rent expense was $86,667 and $73,617, respectively.our three named executive officers. two of the Company's senior executives.a severance package forpayments in the event of termination by usthe Company for any reason otherthat includes as defined. The agreements provide for theaone year after termination. The total contingent obligation under the employment contracts as of December 31, 2013September 30, 2014 is approximately $692,000.In connection with Sterling McDonald’s retirement announced$473,000.January 2014, we expect to pay Mr. McDonald a severanceits Mississippian Lime properties in Kay County, Oklahoma for approximately $400,000, net of $478,000 representing his base salarycustomary closing adjustments, and anticipated bonus under our Cash Incentive Plan and $70,000 in other benefits. In addition, we will accelerate the vestingbuyer's assumption of Mr. McDonald’s previously unvested restricted stock awards which will result in $220,500all abandonment liabilities. stock compensation expense to us.Delhi Payout. We are presently in a dispute with the Delhi Field Operator concerning charges arising fromin northeast Louisiana, has informed the environmental event that began in June 2013. We believe the Operator has indemnified us for such events, with the effectCompany of its preliminary determination that payout should notoccurred during the month of October 2014 and that the Company will earn its reversionary working interest of 23.9% and associated revenue interest of 19.1% in the Delhi Field effective November 1, 2014. When combined with our existing 7.4% royalty and overriding royalty interests, our total net revenue interest will increase to 26.5%, while we will now be delayed. To date, the Operator has not agreed to the applicationresponsible for paying 23.9% of the indemnityoperating costs and their 2006 assumptioncapital expenditures going forward.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.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.Corporation.16Corporation and its wholly owned subsidiaries.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. 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 of our common stock.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:·Enhanced Oil Recovery (EOR), and·Bypassed Primary Resourcesbase 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.SecondFirst Quarter Fiscal 20142015 and Project UpdateQ2-14”Q1-15” & “current quarter” is the three months ended December 31, 2013,September 30, 2014, the company’s 2nd1st quarter of fiscal 2015.“prior“year-ago quarter” is the three months ended September 30, 2013, the company’s 1st1st quarter of fiscal 2014.“Q2-13” & “year-ago quarter” is the three months ended December 31, 2012, the company’s 2nd quarter of fiscal 2013.Q2-14, the Company incurredQ1-15, we earned $1.0 million, or $0.03 per diluted common share, a net loss of $0.6 million due to $2.1 million of one-time charges, compared to net income of $1.3 million in the prior quarter and $1.8 million in the year-ago quarter. The current quarter’s loss was due to a pre-tax $1.3 million restructuring charge, a $0.8 million non-recurring charge associated with the restructuring and stock option exercises, higher G&A expense, a higher income tax expense, and lower revenues, partially offset by reduced LOE.·Current quarter revenue decreased 5% sequentially to $4.4 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. The26% decrease from the year-ago quarter is primarily due to lower Delhi revenue driven by both lower volumes and prices, as well asa 33% decline from the absence of Giddings properties that were divested in late December 2012, offset by the addition of GARP® production.previous quarter.Black oil volumes accounted for 96% of total volumes and 99% ofCurrent quarter revenues during Q2-14, compared sequentially to 96% of volume and 99% of revenues in the prior quarter, whilewere $4.0 million, a 14% decrease from the year-ago quarter’s oil volume was 82% of volumequarter and 95% of revenue. Delhi oil volumes increased 6%a 7% decline from the priorprevious quarter. 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 toRealized price per barrel declined 4.6% from 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 priorprevious 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%10% from the year-ago quarter to $30.64,$98.96 per barrel.natural gas price increased 9% sequentiallydistributing $3.3 million to $3.21our common shareholders in the form of cash dividends.was flat comparedproject information is included under Item 1. Business, Item 2. Properties, Notes to the year-ago quarter.Financial Statements EOR Project·ProductionField EOR—Northeast Louisianaour Delhi enhanced oil recovery project increased 6% sequentially and decreased 9%the first quarter of fiscal 2015 was 5,739 BOPD, down 3% from the year-agofourth quarter to 464 BOPD net to our 7.4% royalty interest (6,264 gross BOPD). The sequential increase was due in part to resumption of CO2 injection in a portion of the field followinglast fiscal year and down 3% from the essential completion of theyear ago quarter. As previously disclosed, remediation of a fluids releasethe operator has deferred capital spending 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 combined with the remediation expense, net of any insurance reimbursements, is expected to delay thesince early 2013 pending reversion of our 24% working interest, and has also chosen to later in 2014, excludingoperate the effectfield at a slightly lower reservoir pressure, which lowers the rate of any indemnity of usoil production without reducing miscibility or lowering ultimate reserves.operator. To date,operator of its preliminary determination that payout occurred during the operator has not agreed tomonth of October 2014 and the applicationCompany will earn its approximate reversionary working interest of 23.9% (with related 19.1% net revenue interest) in the indemnity and their 2006 assumption of environmental liabilities, andDelhi Field effective November 1, 2014. With this reversion, 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. The litigation asserts various breaches of the 2006 purchase and sale agreement between us and the operator including charging our payout account forhave plans to resume expansion of the cost of their remediation work, failure to timely assign us our reversionary working interest due to unallowed chargesCO2 flood 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 costeast and begin construction of thea recycle gas 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 will increase from 0% to 23.9%.·Realized oil prices at Delhi decreased 12% sequentially and decreased 7% from the year-ago quarter to $97 per BO. Realized prices were $110 per BO in the previous quarter and $104 per BO in the year-ago quarter.·The operator has stated its intention to install a plantfield to recover methane and natural gas liquids while making the flood more efficient. We believe that these actions bode well for future increases in production rates from the recycle gas stream, targetingfield.some timethis customer in calendar 2015, an earlier date than projectedwhich wellbore obstructions limited production, and utilized it on the first of these two wells. We have seen a positive response from the first two productive GARP® wells under this agreement completed during the previous quarter, although high operating costs and a low net-back from gas processing under the customer’s pre-existing gas sales contract in the first few months have limited the revenues from our June 30, 2013 reserve report. The operator has further stated its intention to delay significant further capital expenditures untilnet profits interest.reversion has occurred. Proved oil reserves net to our interest are 74% developedthree Company-operated wells, which temporarily suspended production during portions of the quarter and probable reserves are 48% developed as of June 30, 2013, based on our independent engineer’s report as filed in our 2013 Form 10-K.(Gas Assisted Rod Pump)·revenues.entered into an agreement with a large independent operator to install GARP® in ten wells in the Giddings Field. The operator has the option to terminate the second five installations basedclosed on uneconomic performance in the first five installations. We will pay for the intangible costs of installation and the operator will provide the wells, leases and most required tangible equipment. We will earn a fee equal to twenty-five percent 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 agreement in the future.·Our current commercial GARP® installations continue to perform as expected.Projects — Non-Core AssetsMississippi Lime·We undertook the recompletion of the Sneath well to plug off production from 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. Production testing is underway. Unless we achieve more encouraging results, we do not currently contemplate further development of our leasehold this fiscal year.Lopez Field (South Texas) — Sold in December 2013·Effective December 1, 2013, we completed the sale of all of our producing assets and our undeveloped reservesremaining interests in the Lopez Field. HadMississippian Lime project for cash proceeds of approximately $400,000, subject to customary closing adjustments. This transaction completes the divestment been completed at the beginningprocess of the quarter, our production would have been reduced 7.0 BOE per day with approximately $57,000divesting 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 for the six months ended December 31, 2013.RestructuringOn November 1, 2013, we undertook an initiative refocusing our operating resources on growing our Delhi Field EOR project, commercializationall of our GARP® patented artificial lift technologynon-core oil and directly rewarding our common shareholders with continuing cash distributions. Results during the current quarter include:·Reduced our workforce 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 employeesgas properties which we commenced in exchange for non-compete clauses. Of the charge, $376,000 was non-cash expense related to accelerated stock compensation vesting.·Recorded $0.8 million of one-time pre-tax charges arising 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 for the six months ended December 31, 2013. The Option Deductions have driven our tax earnings and profits account into deficit, making cash dividends a return of capital to the receiving shareholder.See a full discussion 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.December 31, 2013,September 30, 2014, our working capital was $25.2$21.9 million, compared to working capital of $24.8$23.3 million at June 30, 2013.2014. The $0.4major factors which resulted in the $1.4 million increasedecrease were the payment of $1.5 million in working capital since June 30, 2013 was due primarily to $0.6annual incentive compensation in September 2014 that reduced our net cash flow from operations and the payment of $3.3 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 highercommon stock dividends in the current liabilities.quarter.sixthree months ended December 31, 2013,September 30, 2014, cash flows provided by operating activities were $2.8$0.6 million, reflecting $3.1$1.6 million provided by operations before $0.3$1.0 million was used by other working capital.capital changes, primarily for the payment of annual incentive compensation. Of the $3.1$1.6 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$0.5 million was attributable to non-cash expenses.sixthree months ended December 31, 2012,September 30, 2013, cash flows provided by operating activities were $5.0$1.6 million, reflecting $6.0$2.3 million provided by operations before $1.0$0.7 million was used in working capital. Of the $6.0$2.3 million provided before working capital changes, $3.1$1.5 million was due to net income and $2.9$0.8 million was due primarily to non-cash expenses.sixthree months ended December 31,September 30, 2013 was $0.9 million.$594,000. Development activities were predominantly for GARP® installations in Giddings and additional testing in the Hendrickson well in the Mississippi Lime. We received approximately $544,000$67,000 of additional proceeds from asset sales, including $400,000 forrelated to the recent salesJune 2013 sale of our South Texas properties.Cash paid for oil and gas capital expenditures during the six months ended December 31, 2012 was $4.0 million. Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and two producer wells were completed. In Giddings, expenditures were centered on installing GARP® on a fourth commercial demonstration well. An inflow of $3.1 million was received for proceeds from the sales of a portioncertain of our Giddings exploration and productionField 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 reconciled 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.sixthree months ended December 31, 2013,September 30, 2014, we used $1.9$3.0 million in cash for financing activities including cash inflowsprincipally consisting 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$3.3 million for common dividends, $0.3 millionstock dividend payments and $169,000 for preferred dividends and $1.1 million for treasury stock purchasesdividend payments, offset partially by $537,000 of cash provided by tax benefits related to incentive stock warrant and stock option exercises and restricted stock vestings.sixthree months ended December 31, 2012,September 30, 2013, we paid preferred dividends of $0.3 million, in addition to a minimal amount$169,000 and purchased $117,000 of treasury stock purchasesthrough the stock surrender of certain employees in satisfaction of payroll liabilities for contemporaneous restricted stock vesting. deferred loan costs.Capital Budget2fundbe incurred over portions of the next two fiscal years. Total spending based on proved reserves in the reserve report, net to our interest, is 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 our interests in the Field will be in excess of the net capital expenditures required.of our remaining fiscal 2014 Capital Plan, the total of whichcapital expenditures is uncertain at this time, with our $25.2 million ofexpected to be met from current working capital on hand at December 31, 2013 and internally generated fundscash flows from operations. Our capital budget includespreference is to remain debt free, but we do have access to a $5 million unsecured revolving line of credit and are in discussions to convert this line to a senior secured facility with up to $17$30 million of developmentcapacity. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi subjector other future capital needs or opportunities.actualexcess cash flow from the Delhi Field, after reversion date of our working interest, andwill permit the rate at which calendar 2014 capital is expended there. Our GARP® business is expectedBoard of Directors 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 drillingbegin considering prudent increases in the Mississippian Lime assets.periodperiods ended December 31,September 30, 2014 and 2013 and 2012 Three Months Ended September 30, 2014 2013 Variance Variance % Delhi field: Crude oil revenues $ 3,868,602 $ 4,429,811 $ (561,209 ) (12.7 )% Crude oil volumes (Bbl) 39,094 40,279 (1,185 ) (2.9 )% Average price per Bbl $ 98.96 $ 109.98 $ (11.02 ) (10.0 )% Artificial lift technology: Crude oil revenues $ 74,980 $ 101,873 $ (26,893 ) (26.4 )% NGL revenues 22,227 23,196 (969 ) (4.2 )% Natural gas revenues 15,552 17,022 (1,470 ) (8.6 )% Service revenue $ 3,097 $ — 3,097 Total revenues $ 115,856 $ 142,091 $ (26,235 ) (18.5 )% Crude oil volumes (Bbl) 772 946 (174 ) (18.4 )% NGL volumes (Bbl) 744 768 (24 ) (3.1 )% Natural gas volumes (Mcf) 4,439 5,889 (1,450 ) (24.6 )% Equivalent volumes (BOE) 2,256 2,696 (440 ) (16.3 )% Crude oil price per Bbl $97.12 $107.69 $ (10.57 ) (9.8 )% NGL price per Bbl $29.88 $30.20 (0.32 ) (1.1 )% Natural gas price per Mcf $3.50 $2.89 0.61 21.1 % Equivalent price per BOE $49.98 $52.70 $ (2.72 ) (5.2 )% Artificial lift production costs (b) $ 197,360 $ 163,749 $ 33,611 20.5 % Artificial lift production costs per BOE 87.48 60.74 $ 26.74 44.0 % Other properties: Revenues $ 20,369 $ 61,797 $ (41,428 ) (67.0 )% Equivalent volumes (BOE) 285 668 (383 ) (57.3 )% Equivalent price per BOE $ 71.47 $ 92.51 $ (21.04 ) (22.7 )% Production costs $ 88,022 $ 254,501 $ (166,479 ) (65.4 )% Production costs per BOE $ 308.85 $ 380.99 $ (72.14 ) (18.9 )% Combined: Oil and gas DD&A (a) $ 260,160 $ 301,752 $ (41,592 ) (13.8 )% Oil and gas DD&A per BOE $ 6.25 $ 6.91 $ (0.66 ) (9.6 )% $8,222$109,190 and $14,462,$7,921, for the three months ended December 31,September 30, 2014 and 2013, respectively.2012,$42,000, for the three months ended September 30, 2014 and 2013, respectively. (Loss) Available to Common Shareholders. For the three monthsquarter ended December 31, 2013,September 30, 2014, we incurred agenerated net lossincome to common shareholders of $577,459$1.0 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.$4.0 million. This compares to a net income of $1,790,696,$1.3 million, or $0.06$0.04 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$4.6 million for the year-ago quarter. Increased revenues were offset by higher operating expensesThe earnings decline is due to lower revenue and higher income tax, reflecting a higher effective income tax rate.rate, partially offset by lower general and administrative expenses. Additional details of the components of net income are explained in greater detail below.Sales Volumes.Delhi Field Crude. Revenues decreased 13% to $3.9 million as a result of a 3% decline in production volumes from the year ago quarter and a 10% decline in realized crude oil NGLs,prices, from $109.98 per barrel to $98.96 per barrel. There are no production costs in the Delhi Field, as all current revenues derive from mineral and natural gas sales volumes, netoverriding royalty interests.our interest, for the three months ended December 31, 2013 decreased 27% to 46,898 BOE’s compared to 64,016 BOE’s for the year-ago quarter. This 17,118$116,000 reflecting a 16% volume decrease, primarily reflects lower Giddings Field volumes, impacted by properties sold in Fiscal 2013,as a result of workovers on the Philip DL #1 and Selected Lands #2 wells, together with a 5% decrease in Delhi Field volumes. Our crude oil sales volumesthe realized price per BOE. We recorded $3,000 of service revenue from the recent GARP® initial installations for a third-party customer. Those two wells did not contribute meaningful net profits to the Company in this quarter, but we believe they will do so in future quarters. Artificial lift production costs were $197,000, which included $149,000 in costs for the current quarter include 42,673 from our interestsabove workovers, which were successful in Delhiincreasing production.2,257 barrels from the Giddingsgas properties since 2013, and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 46,815 barrels from our interests in Delhi and 5,455 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the three months ended December 31, 2013 declined 64%revenues have correspondingly decreased to 847 barrels$20,000 compared to 2,378 barrels in the year-ago-quarter. Current quarter natural gas volumes, virtually all produced at Giddings, decreased 88% to 6,723 mcf from 56,210 mcf$62,000 in the year-ago quarter. AtThe production costs from the prior year were high as a result primarily from workover costs in South Texas and high water production in the Mississippian Lime. With the sale of the remaining interests in our Mississippian Lime properties subsequent to the end of the current quarter, virtually all of Giddings production had been divested, except for our GARP® wells.this divestiture process is now completed.Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $1.3 million to $4.4 million for the current quarter, a 22% decrease from $5.6 million 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, for the current and year-ago quarters.Lease Operating Expenses (including ad valorem and production severance taxes). Lease operating expenses and production taxes for 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.including $0.8decreased $0.4 million, of one-time charges, increased 46%or 22%, to $2.6$1.5 million during the three months ended December 31, 2013September 30, 2014 from $1.8$1.9 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 warrants 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 due primarily to $455,000 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 expenseour December 2013 restructuring, partially offset by $77,000 of lower stockrecent staff additions for GARP®. Salaries and benefits declined $231,000, incentive compensation decreased $60,000 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.Restructuring Charges. We booked $1.3 million of restructuring expense in the current 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.declined by $130,000.Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased 6.6%increased $60,000, or 19%, to $327,168$369,000 for the three months ended December 31, 2013,current quarter compared to $350,119$310,000 for the year-ago quarter. This change was principally due toDD&A of our oil and gas properties decreased by $41,000 on lower production and a 30% increase in depletionlower rate from $5.24per BOE ($6.25 versus $6.91 per BOE in the year-ago quarterquarter), while our other DD&A increased by $101,000. This increase primarily includes depreciation of $21,000 related to $6.80artificial lift equipment installed in the current quarter partially offset by an 27% decline in volume as described above. Muchwells 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.Six month period ended December 31, 2013 and 2012The following table sets forth certain financial information with respect to our oil and natural gas operations:
December 31,(a)Excludes depreciation of office equipment, furniture and fixtures, and other assets of $16,143 and $26,711 for the six months ended December 31, 2013 and 2012, respectively.Net Income Available to Common Shareholders. For the six months ended December 31, 2013, we generated net income of $726,417 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 for the corresponding year-ago period. The earnings decline is due to lower revenue and higher operating expense partially offset by lower income taxes. Additional details of the components of net income are explained in greater detail below.Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the six months ended December 31, 2013 decreased 23% to 90,541 BOE’s compared to 117,457 BOE’s for the year-ago period. This 26,916 volume decrease primarily reflects the loss of production and sales volumes of properties sold 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 barrels from our interests in Delhi and 10,084 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the six months ended December 31, 2013 declined 72% to 1,644 barrels compared to 5,759 barrels in the year-ago period. Current period natural gas volumes, virtually all produced at Giddings, decreased 89% to 12,910 mcf from 122,079 mcf for in the six months ended December 31, 2012.Petroleum Revenues. Crude oil, NGLs and natural gas revenues decreased $0.9 million to $9.0 million for the six months ended December 31, 2013, a 9% decrease from $9.9 million in the year-ago period due to a 23%volume decline partially offset by a 18% higher price per BOE. Prices per BOE were $99.69 and $84.62, respectively, for the six months ended December 31, 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, 2013 decreased $122,953, or 16%, to $654,780 compared to the corresponding year-ago period. Expenses were $54,000 higher at the Lopez Field and $34,000 at our Oklahoma properties, but declined $190,000 in the Giddings Field due to divestitures of non-core 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 for the six months ended December 31, 2013.General and Administrative Expenses (“G&A”). G&A expenses, including $0.8 million of one-time charges, increased 30% to $4.6 million during the six months ended December 31, 2013 from $3.5 million in the year-ago period. 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 expense partially offset by $64,000 of lower legal expense 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.Restructuring Charges. The company booked $1.3 million of restructuring expense in December 2013 primarily reflecting $0.9 million of termination benefits to be paid from January to December 2014third-party customer and a $0.4 million non-cash charge for accelerated restricted stock vesting for terminated employees.Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased by 1.6%$77,000 to $636,841 forexpense the six months ended December 31, 2013, compared to $647,036 for the corresponding year-ago period. This changeunrecovered installation costs of artificial lift equipment which was principally due toremoved from one well and reinstalled in another well 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.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 increases in costs. Product prices, operating costs and development costs may not always move in tandem.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 as 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 enjoyedresulted from our mineral and overriding royalty interests at Delhi. See “Note 12 - Restructuring” within “ Item I. Financial Information.”December 31, 2013.24September 30, 2014.
crude oil, natural gas and NGLs. We December 31, 2013,September 30, 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. As such,2014.information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-Kpricing for our fiscal year ended June 30, 2013.Interest Rate Riskare 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 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 RiskOur 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 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 chose, 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.
December 31, 2013September 30, 2014 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.December 31, 2013September 30, 2014 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.
1415 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 20132014 Annual Report. During the quarter ended December 31, 2013,September 30, 2014, there were no material developments in the status of those proceedings except as described below. 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.
As previously reported, theThe Company and its wholly owned subsidiary are defendants in a lawsuit brought by John C. McCarthy et. al (the “plaintiffs”) in the Fifthfifth District Court of Richland Parish, Louisiana in July 2011. The plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006. On March 29, 2012, the Fifth District Court dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiff’s claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. The plaintiffs are seeking cancellation of the transaction and monetary damages. We subsequently filed a second motion pleading “no cause of action,” with which the district court again agreed and dismissed the plaintiffs’ case on September 23, 2013. Plaintiffs have again filed an appeal.
Onappeal in November 2013. In October 14, 2013,2014, the appellate court reversed the district court. We subsequently filed for 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.
rehearing.
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.
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.
Period (a) Total Number of (b) Average Price (c) Total Number of Shares (d) Maximum Number (or 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 December 31, 2013,September 30, 2014, the Company did not sell any equity securities that were not registered under the Securities Act.December 31, 2013,September 30, 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 and 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.
Shares (or Units)
Purchased
Paid per Share (or
Units)
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs27Period July 1, 2014 to July 31, 2014 99 shares of Common Stock $ 10.94 Not applicable Not applicable August 1, 2014 to August 31, 2014 none Not applicable Not applicable September 1, 2014 to September 30, 2014 5,530 shares of Common Stock $ 9.83 Not applicable Not applicable
None.
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. Certification of Chief Executive Officer pursuant Certification of Chief Financial Officer pursuant XBRL Instance Document XBRL Taxonomy Extension Schema Document XBRL Taxonomy Extension Calculation Linkbase Document XBRL Taxonomy Extension Definition Linkbase Document XBRL Taxonomy Extension Label Linkbase Document XBRL Taxonomy Extension Presentation Linkbase DocumentITEM31.14.1 Form of Contingent Performance Stock Grant under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (Filed herein) 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 31.2 31.232.1 32.1Rule 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 1350.32.2 32.2Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended andto 18 U.S.C. Section 1350.101.INS 99.1Second Amendment to the Evolution Petroleum Corporation 2004 Amended and Restated Stock Plan101.INS101.SCH 101.SCH101.CAL 101.CAL101.DEF 101.DEF101.LAB 101.LAB101.PRE 101.PREBy:/s/ STERLING H. MCDONALDSterling H. McDonaldVice-PresidentBy:/s/ RANDALL D. KEYS Randall D. Keys President and Chief Financial Officer Principal Financial Officer and Principal Accounting Officer Date: November 7, 2014 Date: February 7, 2014