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 $376,365 and $376,365, 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 — 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 Receivables 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 removed or are planned to be removed from three wells of a third-party customer. December 31, June 30, Advances to joint interest operating partner $ 43,646 $ 26,059 Due to joint interest partner 86,289 127,081 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 Company's directors. See Note 10 - Stock-Based Incentive Plan. 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. 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 service period. 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 2014. 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 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 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 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 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. 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. For the twelve months ended December 31, 2014 $ 159,011 2015 159,011 2016 92,756 Total $ 410,778 Type of Cost December 31, Salary Expense $ 616,000 Cash Incentive Plan 186,000 Stock Compensation Expense 376,000 Other Benefits 154,000 Total Restructuring Charges $ 1,332,000 technology. We are focused on increasing underlying 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 Mississippi Lime project. 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 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 % ® equipment installations on two wells of a third party customer. 2013 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 %xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 193420132014Nevada41-1781991Nevada 41-1781991 (State or other jurisdiction of incorporation or organization) xý No: oxý No: oxýJanuary 31, 2014,February 2, 2015, was 32,394,999.Table of ContentsPagePage 67252526272828282829 December 31,
2014 June 30,
2014Assets Current assets Cash and cash equivalents $ 22,523,164 $ 23,940,514 Receivables 2,924,570 1,457,212 Deferred tax asset 159,624 159,624 Prepaid expenses and other current assets 677,756 747,453 Total current assets 26,285,114 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, net 333,001 424,827 Total property and equipment 38,869,734 38,246,897 Other assets 578,405 464,052 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 payable 45,392 — Accrued liabilities and other 811,821 2,558,004 Total current liabilities 5,678,227 2,999,726 Long term liabilities Deferred income taxes 10,553,861 9,897,272 Asset retirement obligations 727,124 205,512 Deferred rent 27,148 35,720 Total liabilities 16,986,360 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, respectively 32,860 32,615 Additional paid-in capital 36,035,076 34,632,377 Retained earnings 12,678,640 17,212,213 Total stockholders’ equity 48,746,893 51,877,522 Total liabilities and stockholders’ equity $ 65,733,253 $ 65,015,752 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 technology 63,236 189,894 179,092 331,985 Other properties — 72,159 20,369 133,956 Total revenues 7,708,067 4,392,289 11,712,894 9,025,988 Operating costs Production costs - Delhi Field 2,817,866 — 2,817,866 — Production costs - artificial lift technology 191,553 153,221 388,913 316,970 Production costs - other properties 9,390 83,309 97,412 337,810 Depreciation, depletion and amortization 917,757 327,168 1,287,107 636,841 Accretion of discount on asset retirement obligations 8,137 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 costs 5,545,773 4,550,384 7,709,734 7,220,186 Income (loss) from operations 2,162,294 (158,095 ) 4,003,160 1,805,802 Other Interest income 7,662 7,701 20,425 15,404 Interest (expense) (12,159 ) (16,582 ) (30,619 ) (33,095 ) Income (loss) before income taxes 2,157,797 (166,976 ) 3,992,966 1,788,111 Income tax provision 917,879 241,907 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 stock 168,576 168,576 337,151 337,151 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 Basic 32,825,631 30,063,676 32,754,016 29,335,498 Diluted 32,947,280 30,063,676 32,884,754 32,377,918 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. months and six months ended December 31, 2013 included non-cash stock-based compensation expense of $376,365.
December 31, 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 amortization 1,311,425 657,265 Stock-based compensation 488,357 689,860 Stock-based compensation related to restructuring — 376,365 Accretion of discount on asset retirement obligations 12,773 25,346 Settlements of asset retirement obligations (220,522 ) (57,247 ) Deferred income taxes 656,589 329,667 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 assets 69,697 (367,426 ) Accounts payable and accrued expenses 1,384,201 222,968 Income taxes payable 45,392 (233,548 ) Net cash provided by operating activities 4,640,908 2,827,053 Cash flows from investing activities Proceeds from asset sales 389,166 544,442 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 options 51,600 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 compensation 921,581 386,976 Maturity of certificate of deposit — 250,000 Recovery of short swing profits (62,958 ) — Deferred loan costs 66 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 period 23,940,514 24,928,585 Cash and cash equivalents, end of period $ 22,523,164 $ 25,542,782 Evolution Petroleum Corporation and SubsidiariesConsolidated 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: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 equipment 1,410,420 (223,846 ) Oil and natural gas property costs incurred through recognition of asset retirement obligations 562,482 48,988 Previously acquired Company common shares swapped by holders to pay stock option exercise price — 618,606 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 — — 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, 2014 317,319 $ 317 32,860,087 $ 32,860 $ 36,035,076 $ 12,678,640 $ — $ 48,746,893 (“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.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 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.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”). Property and Equipment20132014 and June 30, 20132014 our receivables consisted of the following: December 31,
2014 June 30,
2014Receivables from oil and gas sales $ 2,198,912 $ 1,456,146 Receivable from suspended overriding royalty interest (a) 712,100 — Other 13,558 1,066 Receivables $ 2,924,570 $ 1,457,212 December 31,
2014 June 30,
2014Prepaid insurance $ 155,827 $ 169,288 Equipment inventory 28,898 85,888 Prepaid other 34,320 42,800 Retainers and deposits 26,978 29,478 Prepaid federal and Louisiana income taxes 431,733 419,999 Prepaid expenses and other current assets $ 677,756 $ 747,453
2013
2013Unproved property not subject December 31,
2014 June 30,
2014Oil 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 cost 595,877 377,943 Less: Accumulated depreciation (549,696 ) (296,294 ) Other property and equipment, net $ 333,001 $ 424,827 amortization consists of unevaluated acreage of $4.2 million and $4.1 million as ofUnaudited Consolidated Condensed Financial Statements20132014, 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.35— Joint Interest AgreementOther AssetsEffective April 17, 2012, a wholly owned subsidiaryCompany entered into definitive agreementsfollowing: December 31,
2014 June 30,
2014Trademarks $ 43,333 $ 40,928 Patent costs 387,528 305,592 Less: Accumulated amortization of patent costs (35,678 ) (27,050 ) Deferred loan costs 305,961 243,003 Less: Accumulated amortization of deferred loan costs (122,739 ) (98,421 ) Other assets, net $ 578,405 $ 464,052 December 31,
2014 June 30,
2014Accrued incentive and other compensation $ 557,516 $ 1,358,653 Accrued restructuring charges — 530,412 Officer retirement costs 41,954 288,258 Asset retirement obligations due within one year 10,219 146,703 Accrued royalties 78,530 89,179 Accrued franchise taxes 74,414 87,575 Other accrued liabilities 49,188 57,224 Accrued liabilities and other $ 811,821 $ 2,558,004 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:
2013
2013Type of Cost Payments Adjustment to Cost December 31, 2014 Salary continuation liability $ 615,721 $ (615,721 ) $ — $ — Incentive compensation costs 185,525 (185,525 ) — — Other benefit costs and employer taxes 154,575 (110,144 ) (44,431 ) — Accrued restructuring charges $ 955,821 $ (911,390 ) $ (44,431 ) $ — 48—Asset Retirement Obligationsare reconciliationsis aobligation balances:
2013
20138obligations for the six months ended December 31, 2014, and for the year ended June 30, 2014: December 31,
2014 June 30,
2014Asset 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 discount 12,773 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 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. 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 ProfitIn 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.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 perDirectors.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.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.610— —Stock-Based Incentive Plan“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, 2013.2014.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 WarrantsOptionsissued, 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 WarrantsFor 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.and Incentive Warrants as of December 31, 2013,2014, and the changes during the fiscal year:
Options
and Incentive
Warrants
Exercise Price
Intrinsic Value
(1)
Average
Remaining
Contractual
Term (in
years) Stock Options outstanding at July 1, 2014 178,061 $ 2.08 Exercised (37,000 ) 1.39 Stock Options outstanding at December 31, 2014 141,061 2.25 $ 729,991 1.3 Vested or expected to vest at December 31, 2014 141,061 2.25 729,991 1.3 Exercisable at December 31, 2014 141,061 $ 2.25 $ 729,991 1.3 12.347.43 as of December 31, 2013)2014) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock OptionsOptions.Incentive Warrants.There were 4,069,815Contingent Restricted Stock OptionsWarrants exercised duringamortized over the six months ended December 31, 2013 with an aggregate intrinsic value of $41,247,805.2012 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.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.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 StockStock-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, 2013.2013:
Restricted
Shares
Average
Grant-Date
Fair ValueAt December 31, 2013, unrecognized stock2014: Unamortized Compensation Expense at December 31, 2014 (1) Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2014 140,067 $ 8.70 Service-based awards granted 100,910 9.53 Performance-based awards granted 76,642 10.05 Market-based awards granted 35,914 7.59 Vested (64,536 ) 8.59 Forfeited — — Unvested at December 31, 2014 288,997 $ 9.23 $ 1,749,848 2.6 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 granted 38,325 $ 10.05 Market-based awards granted 17,961 4.26 Unvested at December 31, 2014 56,286 $ 8.20 $ 68,507 3.0 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.711—Fair Value Measurement8 12—Income Taxes 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.Our estimated annualrate 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. TheOption 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%.913 —Net Income (Loss) Per Share 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 — Basic 32,825,631 30,063,676 32,754,016 29,335,498 Effect of dilutive securities: Contingent restricted stock grants 6,432 — 1,785 — Stock options 115,217 — 128,953 3,042,420 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,947,280 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 Potential Dilutive Securities Contingent restricted stock grants — 56,286 Stock options $ 2.25 141,061 $ 1.61 197,347
Average
Exercise Price
December 31,
2013Outstanding potentially dilutive securities as of December 31, 2012 were as follows:
Average
Exercise Price
December 31,
2012Outstanding Potential Dilutive Securities At
December 31,
2013Stock options $ 2.01 753,005 10 -14 — Unsecured Revolving Credit Agreementyear 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.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.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 atTheirThe maximum term of letters of credit is one year.for compensating the Lender $50,000 for incurredin loan costs incurred upon closing.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.1115 — 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. Forproceedings, see “Part II, Item 1. Legal Proceedings.”20132014 under this operating lease are as follows:For the twelve months ended December 31, 2015 $ 159,011 2016 92,756 Total $ 251,767 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.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 — RestructuringOn 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:
201320132014 (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 ofin 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:·mature fields.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.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.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“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.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.·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.Projects — Core AssetsDelhi 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.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.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.·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.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. time in calendar 2015,or all this disputed interest to Denbury, then our future reserves, value of reserves and revenues would be negatively impacted.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.GARPGARP® (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.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 AssetsMississippi Lime·We undertookpatents that will address the recompletion offollowing issues: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.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.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.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.2013.RestructuringOn 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.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 Activities2013. 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 ResourcesAt 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.Cash Flows from Operating Activities$2.0$0.7 million was attributable to other non-cash expenses.For2012,2014 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.Cash Flows from Investing ActivitiesGARP® 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.paid for oil and gas capital expenditures duringFlows from Financing Activities2012 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 ActivitiesInstock-based compensation.six monthsquarter ending December 31, 2014, our net share of the joint interest billed capital expenditures was approximately $1.5 million.2012, we paid preferred dividends of $0.3 million, in addition to a minimal amount of treasury stock purchases2014 and deferred loan costs.Capital BudgetWe 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.Results of OperationsThree month period ended December 31, 2013 and 2012 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 revenues 11,028 25,430 (14,402 ) (56.6 )% Natural gas revenues 7,365 21,138 (13,773 ) (65.2 )% Service revenue 2,804 — 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 )% $8,222$216,214 and $14,462,$8,222, for the three months ended December 31, 2014 and 2013, and 2012, respectively.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.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.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.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.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.GARPRestructuring 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.GARPperiodperiods ended December 31, 20132014 and 2012
December 31, 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 revenues 33,255 48,626 (15,371 ) (31.6 )% Natural gas revenues 22,917 38,160 (15,243 ) (39.9 )% Service revenue 5,901 — 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 )% (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.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.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.$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.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.GARPRestructuring 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.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.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.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.”2013.242014.
December 31, 2014. We 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.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 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 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 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 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.
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.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.
1415 — Commitments 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
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.
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 2013,2014, the Company did not sell any equity securities that were not registered under the Securities Act.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.
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 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
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 DocumentITEM31.131.1 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: February 6, 2015 Date: February 7, 2014