UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2017September 30, 2019
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Nevada | | 41-1781991 |
(State or other jurisdiction of incorporation or organization) | | (IRS Employer Identification No.) |
1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant’s telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year if changed since last report)
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Title of Each Class | | Trading Symbol(s) | | Name of Each Exchange On Which Registered |
Common Stock, $0.001 par value | | EPM | | NYSE American |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý No: o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý No: o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filero | o | | Accelerated filer | x |
| Non-accelerated filer | o (Do not check if a smaller reporting company) |
| Smaller reporting company o | x |
Emerging growth company | o | | | | | | | | | |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o No: ý
APPLICABLE ONLY TO CORPORATE ISSUERS:
TheIndicate the number of shares outstanding of each of the registrant’sissuer’s classes of common stock, as of the latest practicable date.
32,935,424 shares outstanding of common stock, par value $0.001, as of February 5, 2018, was 33,171,514.November 4, 2019.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
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Item 2. | | |
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Item 3. | | |
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Item 4. | | |
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Item 4. | | |
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Item 6. | | |
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We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
FORWARD-LOOKING STATEMENTS
This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part II, Item 1A, "Risk Factors" and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in conjunction with our consolidated condensed financial statements and related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.
Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. You are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.
PART I — FINANCIAL INFORMATION
ITEMItem 1. CONSOLIDATEDCONDENSEDFINANCIAL STATEMENTSFinancial Statements (Unaudited)
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited)
| | | December 31, 2017 | | June 30, 2017 | September 30, 2019 | | June 30, 2019 |
Assets | |
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Current assets | |
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Cash and cash equivalents | $ | 25,743,497 |
| | $ | 23,028,153 |
| $ | 31,404,803 |
| | $ | 31,552,533 |
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Receivables | 4,078,153 |
| | 2,726,702 |
| 2,969,052 |
| | 3,168,116 |
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Prepaid expenses and other current assets | 824,048 |
| | 387,672 |
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Prepaid expenses | | 363,059 |
| | 458,278 |
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Total current assets | 30,645,698 |
| | 26,142,527 |
| 34,736,914 |
| | 35,178,927 |
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Oil and natural gas property and equipment, net (full-cost method of accounting) | 60,093,807 |
| | 61,790,068 |
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Oil and natural gas properties, net (full-cost method of accounting) | | 59,554,106 |
| | 60,346,466 |
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Other property and equipment, net | 32,265 |
| | 40,689 |
| 24,096 |
| | 26,418 |
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Total property and equipment | 60,126,072 |
| | 61,830,757 |
| 59,578,202 |
| | 60,372,884 |
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Other assets | 260,468 |
| | 295,384 |
| 351,380 |
| | 210,033 |
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Total assets | $ | 91,032,238 |
| | $ | 88,268,668 |
| $ | 94,666,496 |
| | $ | 95,761,844 |
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Liabilities and Stockholders’ Equity | |
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Current liabilities | |
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Accounts payable | $ | 2,400,202 |
| | $ | 1,994,255 |
| $ | 2,014,031 |
| | $ | 2,084,140 |
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Accrued liabilities and other | 660,467 |
| | 724,639 |
| 471,012 |
| | 537,755 |
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State and federal income taxes payable | | 592,865 |
| | 130,799 |
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Total current liabilities | 3,060,669 |
| | 2,718,894 |
| 3,077,908 |
| | 2,752,694 |
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Long term liabilities | |
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Deferred income taxes | 10,580,381 |
| | 15,826,291 |
| 11,293,608 |
| | 11,322,691 |
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Asset retirement obligations | 1,297,028 |
| | 1,253,628 |
| 1,586,888 |
| | 1,560,601 |
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Operating lease liability | | 126,233 |
| | — |
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Total liabilities | 14,938,078 |
| | 19,798,813 |
| 16,084,637 |
| | 15,635,986 |
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Commitments and contingencies (Note 14) |
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Commitments and contingencies | |
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Stockholders’ equity | |
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Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of December 31, 2017 and June 30, 2017, respectively | 33,171 |
| | 33,087 |
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Common stock; par value $0.001; 100,000,000 shares authorized; 33,003,134 and 33,183,730 shares issued and outstanding, respectively | | 33,003 |
| | 33,183 |
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Additional paid-in capital | 41,538,133 |
| | 40,961,957 |
| 41,458,682 |
| | 42,488,913 |
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Retained earnings | 34,522,856 |
| | 27,474,811 |
| 37,090,174 |
| | 37,603,762 |
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Total stockholders’ equity | 76,094,160 |
| | 68,469,855 |
| 78,581,859 |
| | 80,125,858 |
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Total liabilities and stockholders’ equity | $ | 91,032,238 |
| | $ | 88,268,668 |
| $ | 94,666,496 |
| | $ | 95,761,844 |
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See accompanying notes to consolidated condensed financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
| | | Three Months Ended December 31, | | Six Months Ended December 31, | Three Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 |
Revenues | |
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Crude oil | $ | 10,185,635 |
| | $ | 8,529,817 |
| | $ | 18,014,890 |
| | $ | 16,123,672 |
| $ | 8,845,504 |
| | $ | 11,397,452 |
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Natural gas liquids | 881,276 |
| | — |
| | 1,589,892 |
| | 89 |
| 305,944 |
| | 909,627 |
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Natural gas | — |
| | — |
| | — |
| | (4 | ) | 767 |
| | — |
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Total revenues | 11,066,911 |
| | 8,529,817 |
| | 19,604,782 |
| | 16,123,757 |
| 9,152,215 |
| | 12,307,079 |
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Operating costs | | | | | | | | | | |
Production costs | 2,914,512 |
| | 2,292,421 |
| | 5,806,098 |
| | 4,637,062 |
| 3,090,089 |
| | 3,458,430 |
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Depreciation, depletion and amortization | 1,633,868 |
| | 1,307,510 |
| | 3,152,411 |
| | 2,580,949 |
| 1,449,754 |
| | 1,548,460 |
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Accretion of discount on asset retirement obligations | 23,023 |
| | 13,106 |
| | 44,602 |
| | 26,330 |
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General and administrative expenses * | 1,666,256 |
| | 1,241,399 |
| | 3,235,960 |
| | 2,476,442 |
| 1,338,353 |
| | 1,305,262 |
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Total operating costs | 6,237,659 |
| | 4,854,436 |
| | 12,239,071 |
| | 9,720,783 |
| 5,878,196 |
| | 6,312,152 |
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Income from operations | 4,829,252 |
| | 3,675,381 |
| | 7,365,711 |
| | 6,402,974 |
| 3,274,019 |
| | 5,994,927 |
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Other | |
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Gain on realized derivative instruments, net | — |
| | — |
| | — |
| | 90 |
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Loss on unrealized derivative instruments, net | — |
| | — |
| | — |
| | (14,132 | ) | |
Enduro transaction breakup fee | | — |
| | 1,100,000 |
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Interest and other income | 15,841 |
| | 14,061 |
| | 30,691 |
| | 26,806 |
| 66,129 |
| | 46,571 |
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Interest expense | (20,456 | ) | | (20,711 | ) | | (40,911 | ) | | (41,056 | ) | (29,345 | ) | | (29,345 | ) |
Income before income taxes | 4,824,637 |
| | 3,668,731 |
| | 7,355,491 |
| | 6,374,682 |
| 3,310,803 |
| | 7,112,153 |
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Income tax provision (benefit) | (5,052,211 | ) | | 1,361,097 |
| | (4,661,889 | ) | | 2,250,273 |
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Net income attributable to the Company | 9,876,848 |
| | 2,307,634 |
| | 12,017,380 |
| | 4,124,409 |
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Dividends on preferred stock | — |
| | — |
| | — |
| | 250,990 |
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Deemed dividend on redeemed preferred shares | — |
| | — |
| | — |
| | 1,002,440 |
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Income tax provision | | 517,983 |
| | 1,316,352 |
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Net income available to common stockholders | $ | 9,876,848 |
| | $ | 2,307,634 |
| | $ | 12,017,380 |
| | $ | 2,870,979 |
| $ | 2,792,820 |
| | $ | 5,795,801 |
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Earnings per common share | | | | | | | | | | |
Basic | $ | 0.30 |
| | $ | 0.07 |
| | $ | 0.36 |
| | $ | 0.09 |
| $ | 0.08 |
| | $ | 0.18 |
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Diluted | $ | 0.30 |
| | $ | 0.07 |
| | $ | 0.36 |
| | $ | 0.09 |
| $ | 0.08 |
| | $ | 0.17 |
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Weighted average number of common shares | |
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Basic | 33,109,448 |
| | 33,047,166 |
| | 33,099,546 |
| | 33,002,088 |
| 33,126,645 |
| | 33,102,292 |
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Diluted | 33,140,278 |
| | 33,083,027 |
| | 33,140,257 |
| | 33,037,269 |
| 33,134,372 |
| | 33,119,057 |
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* General and administrative expenses forFor the three months ended December 31, 2017September 30, 2019 and 2016 included2018, non-cash stock-based compensation expense of $484,326expenses were $332,013 and $275,184,$215,373, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $971,810 and $586,872, respectively.
See accompanying notes to consolidated condensed financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
| | | Six Months Ended December 31, | Three Months Ended September 30, |
| 2017 | | 2016 | 2019 | | 2018 |
Cash flows from operating activities | |
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Net income attributable to the Company | $ | 12,017,380 |
| | $ | 4,124,409 |
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Net income | | $ | 2,792,820 |
| | $ | 5,795,801 |
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Adjustments to reconcile net income to net cash provided by operating activities: | |
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Depreciation, depletion and amortization | 3,180,545 |
| | 2,609,356 |
| 1,449,754 |
| | 1,548,460 |
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Stock-based compensation | 971,810 |
| | 586,872 |
| 332,013 |
| | 215,373 |
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Accretion of discount on asset retirement obligations | 44,602 |
| | 26,330 |
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Settlements of asset retirement obligations | — |
| | (121,391 | ) | |
Deferred income taxes (benefit) | (5,245,910 | ) | | 1,709,519 |
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Loss on derivative instruments, net | — |
| | 14,042 |
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Deferred income tax expense (benefit) | | (29,083 | ) | | 275,380 |
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Other | | 18,526 |
| | 4,824 |
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Changes in operating assets and liabilities: | |
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Receivables | (1,351,451 | ) | | (462,981 | ) | 199,064 |
| | (392,981 | ) |
Prepaid expenses and other current assets | (436,376 | ) | | (367,039 | ) | |
Accounts payable and accrued expenses | (83,013 | ) | | (1,955,546 | ) | |
Prepaid expenses | | 95,219 |
| | (415,729 | ) |
Accrued liabilities and other | | (276,864 | ) | | (428,148 | ) |
Income taxes payable | — |
| | (311,306 | ) | 462,066 |
| | 1,053,032 |
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Net cash provided by operating activities | 9,097,587 |
| | 5,852,265 |
| 5,043,515 |
| | 7,656,012 |
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Cash flows from investing activities | |
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Derivative settlement payments paid | — |
| | (318,618 | ) | |
Capital expenditures for oil and natural gas properties | (1,017,358 | ) | | (7,978,130 | ) | (522,413 | ) | | (3,089,006 | ) |
Capital expenditures for other property and equipment | — |
| | (30,447 | ) | |
Net cash used in investing activities | (1,017,358 | ) | | (8,327,195 | ) | (522,413 | ) | | (3,089,006 | ) |
Cash flows from financing activities | |
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Cash dividends to preferred stockholders | — |
| | (250,990 | ) | |
Cash dividends to common stockholders | (4,969,335 | ) | | (3,801,962 | ) | (3,306,408 | ) | | (3,315,785 | ) |
Common share repurchases, including shares surrendered for tax withholding | (395,550 | ) | | (459,858 | ) | (1,362,424 | ) | | (89,992 | ) |
Redemption of preferred shares | — |
| | (7,932,975 | ) | |
Other | — |
| | 32 |
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Net cash used in financing activities | (5,364,885 | ) | | (12,445,753 | ) | (4,668,832 | ) | | (3,405,777 | ) |
Net increase (decrease) in cash and cash equivalents | 2,715,344 |
| | (14,920,683 | ) | |
Cash and cash equivalents, beginning of period | 23,028,153 |
| | 34,077,060 |
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Net change in cash, cash equivalents and restricted cash | | (147,730 | ) | | 1,161,229 |
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Cash, cash equivalents and restricted cash, beginning of period | | 31,552,533 |
| | 27,681,133 |
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Cash and cash equivalents, end of period | $ | 25,743,497 |
| | $ | 19,156,377 |
| $ | 31,404,803 |
| | $ | 28,842,362 |
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| | Supplemental disclosures of cash flow information: | Six Months Ended December 31, | Three Months Ended September 30, |
| 2017 | | 2016 | 2019 | | 2018 |
Income taxes paid | $ | 1,136,754 |
| | $ | 1,278,773 |
| $ | 85,000 |
| | $ | 462,395 |
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Non-cash transactions: | |
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Change in accounts payable used to acquire property and equipment | 424,365 |
| | (1,516,932 | ) | |
Change in accounts payable used to acquire oil and natural gas properties | | 102,981 |
| | (405,645 | ) |
Oil and natural gas property costs incurred through recognition of asset retirement obligations | (779 | ) | | — |
| — |
| | 31,268 |
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See accompanying notes to consolidated condensed financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed StatementStatements of Changes in Stockholders' Equity
For the Six Months Ended December 31, 2017
(Unaudited)
| | | | Common Stock | | | | | | | | | Common Stock | | Additional Paid-in Capital | | Retained Earnings | | Treasury Stock | | Total Stockholders' Equity |
| Additional Paid-in Capital | | Retained Earnings | | Treasury Stock | | Total Stockholders' Equity | Shares | | Par Value | |
| | Shares | | Par Value | | | | | | | | | | | | |
Balance at June 30, 2017 | | 33,087,308 |
| | $ | 33,087 |
| | $ | 40,961,957 |
| | $ | 27,474,811 |
| | $ | — |
| | $ | 68,469,855 |
| |
For the Three Months Ended September 30, 2019: | | | | | | | | | | | | |
Balance at June 30, 2019 | | 33,183,730 |
| | $ | 33,183 |
| | $ | 42,488,913 |
| | $ | 37,603,762 |
| | $ | — |
| | $ | 80,125,858 |
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Issuance of restricted common stock | | 158,785 |
| | 158 |
| | (158 | ) | | — |
| | — |
| | — |
| 59,028 |
| | 59 |
| | (59 | ) | | — |
| | — |
| | — |
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Forfeitures of restricted stock | | (19,561 | ) | | (20 | ) | | 20 |
| | — |
| | — |
| | — |
| (8,248 | ) | | (8 | ) | | 8 |
| | — |
| | — |
| | — |
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Common share repurchases, including shares surrendered for tax withholding | | (55,018 | ) | | — |
| | — |
| | — |
| | (395,550 | ) | | (395,550 | ) | — |
| | — |
| | — |
| | — |
| | (1,362,424 | ) | | (1,362,424 | ) |
Retirements of treasury stock | | — |
| | (54 | ) | | (395,496 | ) | | — |
| | 395,550 |
| | — |
| (231,376 | ) | | (231 | ) | | (1,362,193 | ) | | — |
| | 1,362,424 |
| | — |
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Stock-based compensation | | — |
| | — |
| | 971,810 |
| | — |
| | — |
| | 971,810 |
| — |
| | — |
| | 332,013 |
| | — |
| | — |
| | 332,013 |
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Net income attributable to the Company | | — |
| | — |
| | — |
| | 12,017,380 |
| | — |
| | 12,017,380 |
| |
Common stock cash dividends | | — |
| | — |
| | — |
| | (4,969,335 | ) | | — |
| | (4,969,335 | ) | |
Balance at December 31, 2017 | | 33,171,514 |
| | $ | 33,171 |
| | $ | 41,538,133 |
| | $ | 34,522,856 |
| | $ | — |
| | $ | 76,094,160 |
| |
Net income | | — |
| | — |
| | — |
| | 2,792,820 |
| | — |
| | 2,792,820 |
|
Common stock cash dividends, $0.10 per share | | — |
| | — |
| | — |
| | (3,306,408 | ) | | — |
| | (3,306,408 | ) |
Balance at September 30, 2019 | | 33,003,134 |
| | $ | 33,003 |
| | $ | 41,458,682 |
| | $ | 37,090,174 |
| | $ | — |
| | $ | 78,581,859 |
|
| | | | | | | | | | | | |
| | | | | | | | | | | | |
For the Three Months Ended September 30, 2018: | | | | | | | | | | | | |
Balance at June 30, 2018 | | 33,080,543 |
| | $ | 33,080 |
| | $ | 41,757,645 |
| | $ | 35,498,754 |
| | $ | — |
| | $ | 77,289,479 |
|
Issuance of restricted common stock | | 86,396 |
| | 86 |
| | (86 | ) | | — |
| | — |
| | — |
|
Common share repurchases, including shares surrendered for tax withholding | | — |
| | — |
| | — |
| | — |
| | (89,992 | ) | | (89,992 | ) |
Retirements of treasury stock | | (9,087 | ) | | (9 | ) | | (89,983 | ) | | — |
| | 89,992 |
| | — |
|
Stock-based compensation | | — |
| | — |
| | 215,373 |
| | — |
| | — |
| | 215,373 |
|
Net income | | — |
| | — |
| | — |
| | 5,795,801 |
| | — |
| | 5,795,801 |
|
Common stock cash dividends, $0.10 per share | | — |
| | — |
| | — |
| | (3,315,785 | ) | | — |
| | (3,315,785 | ) |
Balance at September 30, 2018 | | 33,157,852 |
| | $ | 33,157 |
| | $ | 41,882,949 |
| | $ | 37,978,770 |
| | $ | — |
| | $ | 79,894,876 |
|
See accompanying notes to consolidated condensed financial statements.
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 1 — Organization and Basis of Preparation
Nature of Operations. Evolution Petroleum Corporation ("EPM"), together with its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleumoil and gas company headquartered in Houston, Texasfocused on delivering a sustainable dividend yield to its stockholders through the ownership, management and incorporated under the laws of the State of Nevada. We are engaged primarily in the development and production of oil and gas reserves.properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties.
Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United StatesGAAP have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 20172019 Annual Report on Form 10-K for the fiscal year ended June 30, 2017,2019, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.
Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries.subsidiaries (the "Company"). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets and (f)(e) commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
New Accounting Pronouncements.
In August 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") by one year and allows entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method. The Company expects that additional disclosures will be required as a result of adopting ASU 2014-09 and is currently assessing the impact of the guidance on its consolidated financial statements.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal years beginning after December 15, 2017. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 2 — Summary of Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 2 - Summary of Significant Accounting Policies in the 2019 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2019 Form 10-K.
Recently Adopted Accounting Pronouncement - Leases
In February 2016, the FASB issued ASU 2016-02, ,Leases (“ASU 2016-02”("ASC 842"), which relates to the accounting for leasing transactions. This standard requires an entity to recognize a lesseeright-of-use (“ROU”) asset and lease liability for leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. Leases acquired to recordexplore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update.
Effective July 1, 2019, the Company adopted the new standard using a modified retrospective approach and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance, Accounting Standard Codification 840 - Leases. Upon transition, we recognized a ROU asset (or operating lease right-of-use asset) and an operating lease liability with no retained earnings impact. We applied the following practical expedients as provided in the standards update which provide elections to not reassess:
Whether an expired or existing pre-adoption date contracts contained leases.
Lease classification of any expired or existing leases.
Initial direct costs for any expired or existing leases.
We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We capitalize our operating leases on theour consolidated balance sheet through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term greater than one month but less than one year are not capitalized in the above manner but related costs each period must be disclosed.
As a non-operator in recent years and having adequate liquidity, the Company has generally not entered into lease transactions. Presently, our only lease is an operating lease for our corporate office space in Houston, Texas, effective May 1, 2019, which expires November 30, 2022. We have no finance leases and no short-term leases.
Adoption of the new standard did not impact our unaudited condensed consolidated statements of operations, cash flows or stockholders’ equity. At adoption we recorded our operating lease as follows: |
| | | | | | | |
Asset (Liability) | Balance June 30, 2019 | | Adjustment at Adoption July 1, 2019 |
Operating lease right-of-use asset | $ | — |
| | $ | 161,125 |
|
Accrued liabilities and other: | | | |
Deferred rent | $ | (4,338 | ) | | $ | 4,338 |
|
Operating lease liability | $ | — |
| | $ | (26,194 | ) |
Operating lease liabilities - long-term | $ | — |
| | $ | (139,269 | ) |
In addition to the transitional elections, we have also elected a practical expedient to not separate lease components from non-lease components, such as services provided by the lessor under the contract. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. We elected this expedient for our existing asset classes.
Although we presently have no short-term leases, we have made an accounting policy election not to apply the lease recognition requirements to any future short-term leases, which the guidance defines as having a lease term of 12 months or less and not having an option to purchase the underlying asset that we would be reasonably certain to exercise. Such lease
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
payments would be recognized in our statement of operations on a straight-line basis over the lease term as would have been done under the previous guidance.
Variable lease payments, which are neither fixed by the contract nor dependent on an index or rate, are not included in the lease liability or ROU assets. We recognize such payments in our statement of operations in the period in which the obligation for those payments is incurred.
Recently Issued Accounting Pronouncement
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and liabilitiescertain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for the rights and obligations created by leases with lease terms of more than twelve months. In addition,losses. The amendments in this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will beASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts2019, and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, withand early adoption permitted, provided that it is adoptedpermitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in its entirety inwhich the same period. Currently, the Company doesguidance is effective. The adoption of ASU 2016-13 is currently not expect the impact of adopting ASU 2016-15expected to have a material effect on itsour consolidated statements of cash flows.
Note 2 — Receivables
As of December 31, 2017 and June 30, 2017, our receivables consisted of the following:
|
| | | | | | | |
| December 31, 2017 | | June 30, 2017 |
Receivables from oil and gas sales | $ | 4,078,153 |
| | $ | 2,722,880 |
|
Other | — |
| | 3,822 |
|
Total receivables | $ | 4,078,153 |
| | $ | 2,726,702 |
|
Note 3 — Prepaid Expenses and Other Current Assets
As of December 31, 2017 and June 30, 2017, our prepaid expenses and other current assets consisted of the following:
|
| | | | | | | |
| December 31, 2017 | | June 30, 2017 |
Prepaid insurance | $ | 86,904 |
| | $ | 169,416 |
|
Retainers and deposits | 7,589 |
| | 7,553 |
|
Prepaid federal and state income taxes | 674,028 |
| | 121,232 |
|
Other prepaid expenses | 55,527 |
| | 89,471 |
|
Prepaid expenses and other current assets | $ | 824,048 |
| | $ | 387,672 |
|
financial statements.
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 3 — Revenue from Contracts with Customers
All of our revenue is generated from our interests in the Delhi field in Northeast Louisiana except $16 thousand of revenue from an overriding royalty interest retained in a past divestiture included below in fiscal 2020:
|
| | | | | | | |
| Three Months Ended September 30, |
| 2019 | | 2018 |
Revenues | |
| | |
|
Crude oil | $ | 8,845,504 |
| | $ | 11,397,452 |
|
Natural gas liquids | 305,944 |
| | 909,627 |
|
Natural gas | 767 |
| | — |
|
Total revenues | $ | 9,152,215 |
| | $ | 12,307,079 |
|
The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of post-production expenses such as transportation, gathering and processing deductions within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the production costs line item on the accompanying unaudited condensed statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of oil, gas, and NGL production revenue.
Judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers relate primarily to determining the point in time when control of product transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied at a point in time upon control transferring to a customer at a specified delivery point. Consideration is allocated to satisfied performance obligations at the end of an accounting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received one to two months after production has occurred, which is typical in the industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of September 30, 2019 and June 30, 2019 were $3.0 million and $3.2 million, respectively. To estimate accounts receivable from operator contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized during the three months ended September 30, 2019, that related to performance obligations satisfied in prior reporting periods, was immaterial.
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 4 — Enduro Purchase and Sale Agreement and "Stalking Horse" Bid
During the first quarter of fiscal 2019, the Company recorded a $1.1 million break-up fee upon the closing of a higher bidder's purchase transaction. During May 2018, the Company had entered into a Purchase and Sale Agreement ("PSA"), to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. Contemporaneous with executing the PSA, the Company made a $2.75 million deposit to an acquisition escrow account which, together with interest earned, comprised the restricted cash balance on the Company's June 30, 2018 consolidated statement of financial position. Earlier in the first quarter of 2019, the Company was repaid its deposit together with related earned interest when a higher bidder first emerged in the bidding process.
The Company's initial and subsequent bids represented offers under Section 363 of the U.S. Bankruptcy Code in Enduro's Chapter 11 proceeding. Such offers are commonly referred to as “stalking horse” bids and are subject to higher bids, in accordance with the bidding procedures approved by the Bankruptcy Court. In connection with the PSA, the Company had incurred third party due diligence expenses, which have been reflected in the Company's consolidated statement of operations for the year ended June 30, 2018.
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 5 — Receivables
As of September 30, 2019 and June 30, 2019, our receivables consisted of the following:
|
| | | | | | | |
| September 30, 2019 | | June 30, 2019 |
Receivables from oil and NGL sales | $ | 2,967,064 |
| | $ | 3,168,116 |
|
Other | 1,988 |
| | — |
|
Total receivables | $ | 2,969,052 |
| | $ | 3,168,116 |
|
Note 6 — Prepaid Expenses
As of September 30, 2019 and June 30, 2019, our prepaid expenses consisted of the following:
|
| | | | | | | |
| September 30, 2019 | | June 30, 2019 |
Prepaid insurance | $ | 148,351 |
| | $ | 206,198 |
|
Prepaid subscription and licenses | 67,211 |
| | 55,435 |
|
Prepaid federal and state income taxes | 121,679 |
| | 121,679 |
|
Prepaid investor relations and other | 25,818 |
| | 74,966 |
|
Total prepaid expenses | $ | 363,059 |
| | $ | 458,278 |
|
Note 47 — Property and Equipment
As of December 31, 2017September 30, 2019 and June 30, 2017,2019, our oil and natural gas properties and other property and equipment consisted of the following:
| | | December 31, 2017 | | June 30, 2017 | September 30, 2019 | | June 30, 2019 |
Oil and natural gas properties | |
| | |
| |
| | |
|
Property costs subject to amortization | $ | 86,403,877 |
| | $ | 84,962,933 |
| $ | 96,247,547 |
| | $ | 95,622,153 |
|
Less: Accumulated depreciation, depletion, and amortization | (26,310,070 | ) | | (23,172,865 | ) | (36,693,441 | ) | | (35,275,687 | ) |
Unproved properties not subject to amortization | — |
| | — |
| — |
| | — |
|
Oil and natural gas properties, net | $ | 60,093,807 |
| | $ | 61,790,068 |
| $ | 59,554,106 |
| | $ | 60,346,466 |
|
Other property and equipment | |
| | |
| |
| | |
|
Furniture, fixtures, office equipment and other, at cost | $ | 135,377 |
| | $ | 135,377 |
| $ | 154,731 |
| | $ | 154,731 |
|
Less: Accumulated depreciation | (103,112 | ) | | (94,688 | ) | (130,635 | ) | | (128,313 | ) |
Other property and equipment, net | $ | 32,265 |
| | $ | 40,689 |
| $ | 24,096 |
| | $ | 26,418 |
|
During the sixthree months ended December 31, 2017September 30, 2019 and 2016,2018, the Company incurred capital expenditures of $1.4$0.6 million and $6.5$2.7 million, respectively, in the Delhi field.
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 8 — Leases
Operating leases are reflected as an operating lease ROU asset included in other assets, in accrued and other liabilities-current and as an operating lease liability on our unaudited condensed consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.
As an non-operator in recent years and having adequate liquidity, the Company has generally not entered into lease transactions. Presently, our only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. Presently we have one operating lease for office space, no finance leases and no short-term leases.
Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include:
Discount Rate - Our lease does not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term for an amount equal to the lease payments in a similar economic environment. At adoption, July 1, 2019,we used our prime-rate-based borrowing rate under our senior secured credit facility as our incremental borrowing as the term facility was based on a similar term and is appropriately risk-adjusted.
Lease Term - At inception the Company evaluates the contract containing a lease arrangement to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, an option available to extend or to early terminate the arrangement is evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain operational flexibility, there is no available option to extend that the Company is reasonably certain it will exercise. We have no expectation to use the early termination option that we are reasonably certain to exercise.
For the three months ended September 30, 2019, the components of our total lease expense, included in general and administrative expense, are as follows: |
| | | |
| Three Months Ended September 30, 2019 |
Operating lease cost | $ | 13,015 |
|
Variable lease expense (1) | 990 |
|
Total lease expense | $ | 14,005 |
|
(1) Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU asset.
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Supplemental cash flow, balance sheet and other disclosures information related to our operating leases are as follows: |
| | | |
| As of and For the Three Months Ended September 30, 2019 |
Cash Flow: | |
Cash paid for amounts included in the measurement of lease liabilities | $ | — |
|
ROU asset added in exchange for lease obligation at adoption | 161,125 |
|
| |
Balance Sheet: | |
Operating lease ROU asset (included in other assets) | 150,249 |
|
Accrued liabilities - current | 41,369 |
|
Operating lease liability - long-term | 126,233 |
|
| |
Other: | |
Weighted average remaining lease term in years | 3.16 |
|
Weighted average discount rate | 5.15 | % |
Maturities of our operating lease liability are as follows: |
| | | |
Fiscal Year | Operating Lease Liability |
Remainder of 2020 | $ | 34,322 |
|
2021 | 59,945 |
|
2022 | 61,843 |
|
2023 | 26,098 |
|
Total lease payments | 182,208 |
|
Less imputed interest | (14,606 | ) |
Total lease liability | $ | 167,602 |
|
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 59 — Other Assets
As of December 31, 2017September 30, 2019 and June 30, 2017,2019, other assets consisted of the following:
| | | December 31, 2017 | | June 30, 2017 | September 30, 2019 | | June 30, 2019 |
Royalty rights | $ | 108,512 |
| | $ | 108,512 |
| $ | 108,512 |
| | $ | 108,512 |
|
Less: Accumulated amortization of royalty rights | (27,128 | ) | | (20,346 | ) | (50,865 | ) | | (47,474 | ) |
Investment in Well Lift Inc., at cost | 108,750 |
| | 108,750 |
| 108,750 |
| | 108,750 |
|
Deferred loan costs | 168,972 |
| | 168,972 |
| 168,972 |
| | 168,972 |
|
Less: Accumulated amortization of deferred loan costs | (98,638 | ) | | (70,504 | ) | (145,716 | ) | | (141,927 | ) |
Right of use asset under operating lease | | 161,125 |
| | — |
|
Less: Accumulated amortization of right of use asset | | (10,876 | ) | | — |
|
Software license | | 20,662 |
| | 20,662 |
|
Less: Accumulated amortization of software license | | (9,184 | ) | | (7,462 | ) |
Other assets, net | $ | 260,468 |
| | $ | 295,384 |
| $ | 351,380 |
| | $ | 210,033 |
|
Our royalty rights and investment in Well Lift, Inc. ("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own 17.5% of the common stock of WLI and account for our investment underin this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the cost method. Any dividends paid are recorded as income and any returnidentical or a similar investment of capital reduces our cost basis in the investment. Oursame issuer, if such were to occur. The Company evaluates the investment in WLI is evaluated for impairment at least quarterly or when managementit identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.
Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 610 — Accrued Liabilities and Other
As of December 31, 2017September 30, 2019 and June 30, 2017,2019, our other current liabilities consisted of the following:
| | | December 31, 2017 | | June 30, 2017 | September 30, 2019 | | June 30, 2019 |
Accrued incentive and other compensation | $ | 292,382 |
| | $ | 413,113 |
| $ | 182,855 |
| | $ | 369,719 |
|
Accrued severance payments | 46,719 |
| | — |
| |
Asset retirement obligations due within one year | 35,539 |
| | 35,115 |
| 50,244 |
| | 50,244 |
|
Accrued royalties, including suspended accounts | 11,524 |
| | 17,708 |
| |
Operating lease liability, current | | 41,369 |
| | — |
|
Accrued franchise taxes | 82,800 |
| | 150,062 |
| 34,238 |
| | 5,738 |
|
Accrued ad valorem taxes | 191,503 |
| | 108,641 |
| 150,750 |
| | 100,500 |
|
Other accrued liabilities | | 11,556 |
| | 11,554 |
|
Accrued liabilities and other | $ | 660,467 |
| | $ | 724,639 |
| $ | 471,012 |
| | $ | 537,755 |
|
Note 711 — Asset Retirement Obligations
Our asset retirement obligations represent the estimated present value of the amount we expect to incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligations for the sixthree months ended December 31, 2017September 30, 2019 and for the year ended June 30, 2017:2019:
|
| | | | | | | |
| September 30, 2019 | | June 30, 2019 |
Asset retirement obligations — beginning of period | $ | 1,610,845 |
| | $ | 1,422,955 |
|
Liabilities incurred | — |
| | 31,268 |
|
Accretion of discount | 26,287 |
| | 101,506 |
|
Revision of previous estimates | — |
| | 55,116 |
|
Asset retirement obligations — end of period | $ | 1,637,132 |
| | $ | 1,610,845 |
|
Less current portion in accrued liabilities | (50,244 | ) | | (50,244 | ) |
Long-term portion of asset retirement obligations | $ | 1,586,888 |
| | $ | 1,560,601 |
|
|
| | | | | | | |
| December 31, 2017 | | June 30, 2017 |
Asset retirement obligations — beginning of period | $ | 1,288,743 |
| | $ | 962,196 |
|
Liabilities incurred | — |
| | 52,792 |
|
Liabilities settled | — |
| | (157,164 | ) |
Liabilities sold | — |
| | (47,817 | ) |
Accretion of discount | 44,602 |
| | 59,664 |
|
Revision of previous estimates | (778 | ) | | 419,072 |
|
Asset retirement obligations — end of period | $ | 1,332,567 |
| | $ | 1,288,743 |
|
Less current portion in accrued liabilities | (35,539 | ) | | (35,115 | ) |
Long-term portion of asset retirement obligations | $ | 1,297,028 |
| | $ | 1,253,628 |
|
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 812 — Stockholders’ Equity
Common Stock
As of December 31, 2017,September 30, 2019, we had 33,171,51433,003,134 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. We paid dividends of $4,969,335$3,306,408 and $3,801,962$3,315,785 to our common shareholdersstockholders during the sixthree months ended December 31, 2017September 30, 2019 and 2016,2018, respectively. These dividend payments consisted of two quarterlyThe following table reflects the dividends of $0.075 per share each duringpaid within the six months ended December 31, 2017 and quarterly dividend payments of $0.05 and $0.065 per share during the six months ended December 31, 2016.respective three month periods:
|
| | | | | | | |
Common Stock Cash Dividends per Share | 2019 | | 2018 |
First quarter ended September 30, | $ | 0.10 |
| | $ | 0.10 |
|
In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Between June 2015 and December 2015,Since inception of the program through September 30, 2019, the Company spent $1,609,008$2.9 million to repurchase 265,762488,629 common shares at an average price of $6.05$5.98 per share. There have been noshare, including 222,437 shares repurchased inat an average cost of $5.89 during the open market since December 2015.three months ended September 30, 2019. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.
Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
During the sixthree months ended December 31, 2017September 30, 2019 and 2016,2018, the Company also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The treasury shares were subsequently canceled. Such shares were valued at fair market value on the date of vesting, as reflectedvesting. The following table shows all treasury stock purchases in the following table:respective periods:
| | | Six Months Ended December 31, | Three Months Ended September 30, |
| 2017 | | 2016 | 2019 | | 2018 |
Number of treasury shares acquired(1) | 55,018 |
| | 73,455 |
| 231,376 |
| | 9,087 |
|
Average cost per share | $ | 7.19 |
| | $ | 6.26 |
| $ | 5.89 |
| | $ | 9.90 |
|
Total cost of treasury shares acquired | $ | 395,550 |
| | $ | 459,858 |
| $ | 1,362,424 |
| | $ | 89,992 |
|
(1) The fiscal 2019 number of shares is net of 8,939 shares forfeited in the period.
Series A Cumulative Preferred Stock Called for Redemption
In September 2016, the Company announced the decision to redeem all 317,319 outstanding shares of its 8.5% Series A Cumulative Preferred Stock. The redemption occurred in November 2016 at the stated value of $25.00 per share plus all accumulated and unpaid distributions, for an aggregate redemption cost of $7,932,975.
On September 30, 2016, in connection with the planned redemption, the Company recorded a deemed dividend of $1,002,440, representing the difference between the redemption consideration paid and the historical net issuance proceeds of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share.
Dividends on the Series A Cumulative Preferred Stock were paid at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly. During the six months ended December 31, 2016, we paid cash dividends of $250,990 to holders of our Series A Preferred Stock prior to the November 2016 redemption date.
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2017,2019, all preferred and common stock dividends were treated for tax purposes as qualified dividend income to recipients. Based on our current projections for the fiscal year ending June 30, 2018,2020, we expect all common dividends for such period to be treated as qualified dividend income. Such projections are based on our reasonable expectations as of December 31, 2017September 30, 2019 and are subject to change based on our final tax calculations at the end of the fiscal year.
Note 913 — Stock-Based Incentive Plan
At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). for which there were no shares available for future grants. The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of December 31, 2017, 987,845September 30, 2019, 603,239 shares remained available for grant under the 2016 Plan.
At December 8, 2016, there were no shares available for future grants under the 2004 Plan.
Evolution Petroleum Corporation and Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
All outstanding awards granted under the 2004 Plan continue to be subject to the terms and conditions as set forth in the agreements evidencing such awards and the terms of the 2004 Plan. Under these agreements, we have outstanding grants of restricted common stock awards ("Restricted Stock") and contingent restricted common stock awards ("Contingent Restricted Stock") to employees and directors of the Company.
Restricted Stock and Contingent Restricted Stock
The Company awardshas awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting
Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan they were granted under.
During the three months ended September 30, 2019, the only awards granted by the Company were to its new chief executive officer upon his employment. He received 48,872 shares of serviced-based restricted common stock which vest in three equal amounts on June 30, 2020, 2021 and 2022, and was also awarded a total of 200,000 market-based restricted stock units consisting of four equal tranches, each of which may vest only if its respective stock price requirement is met before the award term expires. Each tranche has a separate stated price requirement and respective vesting will occur only if, before July 1, 2023, the ninety-day trailing average Company stock share price equals or exceeds its tranche price requirement.
Service-based awards vest with continuous employment by the Company, generally in annual installments over a four-year period. Certain awards contain other vesting periods, including quarterly installments andtheir terms of three to four years. Awards to the Company's directors have one-year cliff vesting. Restricted Stock grants which vest based on service are valued at the fair market value on the date of grant and amortized over the service period. During the six months ended December 31, 2017, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employees and 66,944 awards to directors, substantially all of which have a one-year vesting period. We did not grant any performance-based or market based awards, nor any Contingent Restricted Stock awards, during this period.
Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four-year term.term of the award. As of December 31, 2017, certain contingentSeptember 30, 2019, there were no performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period.outstanding.
Market-basedMany of our past market-based awards could vest if thetheir respective two- or three-year trailing total returnreturns on the Company’s common stock exceedsexceed the corresponding total returns of various quartiles of indices consisting of either peer companiescompanies. More recent market-based awards vest when the average of the Company's closing stock price over a defined measurement period meets or exceeds a broad market index of companies in our industry.required stock price. The fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.
Unvested Restricted StockFor market-based awards at December 31, 2017 consisted ofgranted during the following:
three months ended September 30, 2019 and 2018, the assumptions used in the Monte Carlo simulation valuations, expected lives and fair values were as follows: |
| | | | | | |
| Number of Restricted Shares | | Weighted Average Grant-Date Fair Value |
Service-based awards | 220,068 |
| | $ | 6.68 |
|
Performance-based awards | 50,360 |
| | 5.67 |
|
Market-based awards | 50,359 |
| | 5.44 |
|
Unvested Restricted Stock at December 31, 2017 | 320,787 |
| | $ | 6.33 |
|
The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2017:
|
| | | | | | | | | | | | |
| Number of Restricted Shares | | Weighted Average Grant-Date Fair Value | | Unamortized Compensation Expense at December 31, 2017 | | Weighted Average Remaining Amortization Period (Years) |
Unvested at July 1, 2017 | 391,624 |
| | $ | 6.22 |
| | | | |
Service-based shares granted | 112,155 |
| | 6.96 |
| | | | |
Vested | (163,431 | ) | | 6.52 |
| | | | |
Forfeited | (19,561 | ) | | 6.16 |
| | | | |
Unvested Restricted Stock at December 31, 2017 | 320,787 |
| | $ | 6.33 |
| | $ | 1,510,203 |
| | 1.39 |
|
| | | | | | | |
| Three Months Ended September 30, |
| 2019 | | 2018 |
Weighted average fair value of market-based awards granted | $ | 3.50 |
| | $ | 8.24 |
|
Risk-free interest rate | 1.87 | % | | 2.69 | % |
Expected vesting term in years | 1.35 |
| | 2.82 |
|
Expected volatility | 43.7 | % | | 41.8 | % |
Dividend yield | 6.0 | % | | 4.0 | % |
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Unvested Contingent Restricted Stock awards at December 31, 2017September 30, 2019 consisted of the following:
|
| | | | | | |
| Number of Contingent Restricted Shares | | Weighted Average Grant-Date Fair Value |
Performance-based awards | 36,688 |
| | $ | 7.04 |
|
Market-based awards | 25,180 |
| | 3.42 |
|
Unvested contingent shares at December 31, 2017 | 61,868 |
| | $ | 5.57 |
|
|
| | | | | | |
| Number of Restricted Shares | | Weighted Average Grant-Date Fair Value |
Service-based awards | 142,132 |
| | $ | 7.83 |
|
Market-based awards | 41,888 |
| | 8.24 |
|
Unvested Restricted Stock at September 30, 2019 | 184,020 |
| | $ | 7.92 |
|
The following table sets forth Contingentthe Restricted Stock transactions for the sixthree months ended December 31, 2017:September 30, 2019:
| | | Number of Contingent Restricted Shares | | Weighted Average Grant-Date Fair Value | | Unamortized Compensation Expense at December 31, 2017 (1) | | Weighted Average Remaining Amortization Period (Years) | Number of Restricted Shares | | Weighted Average Grant-Date Fair Value | | Unamortized Compensation Expense at September 30, 2019 | | Weighted Average Remaining Amortization Period (Years) |
Unvested at July 1, 2017 | 113,270 |
| | $ | 4.64 |
| | | | |
Unvested at July 1, 2019 | | 176,683 |
| | $ | 8.09 |
| | | |
Service-based shares granted | | 48,872 |
| | 6.65 |
| | | |
Vested | (46,630 | ) | | 3.34 |
| | | | (33,287 | ) | | 6.53 |
| | | |
Forfeited | (4,772 | ) | | 5.30 |
| | | | (8,248 | ) | | 9.48 |
| | | |
Unvested contingent shares at December 31, 2017 | 61,868 |
| | $ | 5.57 |
| | $ | 84,005 |
| | 1.03 | |
Unvested Restricted Stock at September 30, 2019 | | 184,020 |
| | $ | 7.92 |
| | $ | 889,543 |
| | 2.06 |
(1) Excludes $115,665Unvested Contingent Restricted Stock awards table below consists solely of potential future compensation expense for contingent performance-based awards for which vesting is not considered probable at this time for accounting purposes.market-based awards:
|
| | | | | | | | | | | | |
| Number of Contingent Restricted Shares | | Weighted Average Grant-Date Fair Value | | Unamortized Compensation Expense at September 30, 2019 | | Weighted Average Remaining Amortization Period (Years) |
Unvested at July 1, 2019 | 10,156 |
| | $ | 3.42 |
| | | | |
Market-based awards granted | 200,000 |
| | 3.50 |
| | | | |
Vested | (10,156 | ) | | 3.42 |
| | | | |
Unvested contingent shares at September 30, 2019 | 200,000 |
| | $ | 3.50 |
| | $ | 574,045 |
| | 1.1 |
Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants for the three months ended December 31, 2017September 30, 2019 and 20162018 was $484,326$332,013 and $275,184, respectively. For the corresponding six month periods, non-cash stock compensation expense was $971,810 and $586,872,$215,373, respectively.
Note 10—Derivatives
From time to time, the Company may use derivative instruments to reduce its exposure to crude oil price volatility of its near-term forecasted production. The Company's objectives are to achieve a more predictable level of cash flows to support the Company’s capital expenditure programs and to provide better financial visibility for the payment of dividends on common stock. The Company may use both fixed price swap agreements and costless collars to manage its exposure to crude oil and other commodity price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes.
The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedging ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in other non-operating income and expense. Given the cost and complexity, the Company has elected not to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, a portion of the change in fair value of the derivative instruments, if effective in hedging the underlying commodity risk, would be deferred in other comprehensive income and recognized in earnings only when the underlying hedged item impacts earnings.
These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As of June 30, 2017 and December 31, 2017, the Company had no derivative asset or liability positions.
The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.
Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
For the six months ended December 31, 2017, the Company had no gains or losses from derivatives. For the six months ended December 31, 2016, the Company recorded a loss on derivative instruments of $14,042 consisting of a realized gain of $90 on settled positions and an unrealized net loss of $14,132.
Note 1114 — Income Taxes
We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ending June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.
Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation of our income tax expense were approximately 20% and 35% for the six months ended December 31, 2017 and 2016, respectively. After adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.
Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation and other permanent differences. The effective tax rate for the six months ended December 31, 2017 was significantly lower than the statutory federal rate as a result of percentage depletion in excess of basis and the tax effects of stock-based compensation, partially offset by state income taxes net of the federal benefit. Our quarterly income tax provisions are based on our reasonable estimates of income taxes payable at the end of the year. These estimates and our estimated interim effective tax rates may change significantly as additional financial results and amounts of capital spending become available during the year. In particular, our estimates of the utilization of excess percentage depletion, which is limited to 65% of actual taxable income, are subject to greater fluctuations between interim periods than other components of our tax provision.
There were neither unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during any periods presented in the financial statements. 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 various 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 ended June 30, 20142015 through June 30, 20172018 for federal tax purposes and for the years ended June 30, 20132016 through June 30, 20172018 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.
For the three months ended September 30, 2019 and 2018, respectively, we recognized income tax expenses of $0.5 million and $1.3 million. For the three months ended September 30, 2019 and 2018, the corresponding effective tax rates were 15.6% and 18.5%. Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation and other permanent differences. For both periods, our respective statutory federal tax rate was 21%.
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
Note 1215 — Net Income Per Share
The following table sets forth the computation of basic and diluted income per share: | | | Three Months Ended December 31, | | Six Months Ended December 31, | Three Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2019 | | 2018 |
Numerator | |
| | |
| | |
| | |
| |
| | |
|
Net income available to common shareholders | $ | 9,876,848 |
| | $ | 2,307,634 |
| | $ | 12,017,380 |
| | $ | 2,870,979 |
| $ | 2,792,820 |
| | $ | 5,795,801 |
|
Denominator | |
| | |
| | |
| | |
| |
| | |
|
Weighted average number of common shares — Basic | 33,109,448 |
| | 33,047,166 |
| | 33,099,546 |
| | 33,002,088 |
| 33,126,645 |
| | 33,102,292 |
|
Effect of dilutive securities: | |
| | |
| | |
| | |
| |
| | |
|
Contingent restricted stock grants | 30,830 |
| | 9,836 |
| | 40,711 |
| | 10,909 |
| 7,727 |
| | 16,765 |
|
Stock options | — |
| | 26,025 |
| | — |
| | 24,272 |
| |
Weighted average number of common shares and dilutive potential common shares used in diluted EPS | 33,140,278 |
| | 33,083,027 |
| | 33,140,257 |
| | 33,037,269 |
| |
Weighted average number of common shares and potentially dilutive common shares used in diluted earnings per share | | 33,134,372 |
| | 33,119,057 |
|
| | | | | | | | | | |
Net income per common share — Basic | $ | 0.30 |
| | $ | 0.07 |
| | $ | 0.36 |
| | $ | 0.09 |
| $ | 0.08 |
| | $ | 0.18 |
|
Net income per common share — Diluted | $ | 0.30 |
| | $ | 0.07 |
| | $ | 0.36 |
| | $ | 0.09 |
| $ | 0.08 |
| | $ | 0.17 |
|
Outstanding potentially dilutive securities as of December 31, 2017 were as follows:
|
| | | | | | |
Outstanding Potentially Dilutive Securities | Weighted Average Exercise Price | | At December 31, 2017September 30, 2019 |
Contingent Restricted Stock grants | $ | — |
| | 61,868200,000 |
|
Outstanding potentially dilutive securities as of December 31, 2016 were as follows:
|
| | | | | | |
Outstanding Potentially Dilutive Securities | Weighted Average Exercise Price | | At December 31, 2016 |
Contingent Restricted Stock grants | $ | — |
| | 113,270 |
|
Stock Options | 2.19 |
| | 35,231 |
|
Total outstanding potentially dilutive securities | $ | 0.52 |
| | 148,501 |
|
|
| | | | | | |
Outstanding Potentially Dilutive Securities | Weighted Average Exercise Price | | At September 30, 2018 |
Contingent Restricted Stock grants | $ | — |
| | 10,156 |
|
Note 1316 — Senior Secured Credit Agreement
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replacesOn May 25, 2018, we entered into the third amendment to our credit agreement governing the revolving credit facility to, among other things, extend the maturity date to April 11, 2021. On December 31, 2018, we entered into the fourth amendment to our credit agreement governing the revolving credit facility to broaden the definition for the Use of Proceeds.
As of September 30, 2019, the Company's previous unsecured credit facility which expired in April 2016. Theelected commitment and borrowing base under the Facility has been set at $10 million and was subsequently increased towere $40 million, effective February 1, 2018. As of December 31, 2017, the Company waswe were in compliance with all financial covenants contained in the Facility, and there were no amounts were outstanding under the Facility, which is secured by substantially all of the Company’s assets.
Under the Facility the borrowing base shall be determined semiannually as of every May 15 and November 15 during the term of the Facility. During the current quarter, the bank performed its periodic fall redetermination of the borrowing base and confirmed our elected amount of $40 million.
Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas, and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.
The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.00%. The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40$50 million, all as defined under the Facility.
Evolution Petroleum Corporation Andand Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements
In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $70,334$23,256 as of December 31, 2017.September 30, 2019.
Note 1417 — Commitments and Contingencies
We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum, we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.
Note 18 — Subsequent Event
On December 3, 2013,November 1, 2019, and effective as of October 1, 2019, our wholly ownedwholly-owned subsidiary, NGS Sub Corp.Evolution Petroleum West, Inc., was served with a lawsuit filedDelaware corporation, purchased a 23.51% non-operating working interest and a 19.70% revenue interest in the 8th Judicial District CourtHamilton Dome field located in Hot Springs County, Wyoming, from entities owned or controlled by Merit Energy Company ("Merit") of Winn Parish, Louisiana by Cecil M. BrooksDallas, Texas. The consideration to Merit consisted of $9.5 million in cash and Brandon Hawkins, residentsour assumption of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed ofasset retirement obligations. The assets included 265 producing and water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damagesinjection wells and other relief. The plaintiffs subsequently filed an amended petition joining the Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. The district court dismissed the claim of Mr. Brooks against NGS Sub Corp. and the Company because Mr. Brooks purchased the land where the well is located subsequent to the divestiture of the property by NGS Sub Corp. The claim of Mr. Hawkins is still being defended. A bench trial is currently scheduled for March 2018. We will continue to vigorously defend the claims and based on the input of our legal counsel, we consider the likelihood of a loss in this matter that is material to the financial position of the Company to be remote.associated facilities.
Lease Commitments. We have a non-cancelable operating lease for office space that expires on May 31, 2019. Future minimum lease commitments as of December 31, 2017 under this operating lease are as follows:
|
| | | |
Twelve months ended December 31, | |
2018 | $ | 73,073 |
|
2019 (through May) | $ | 30,447 |
|
Rent expense for the three months ended December 31, 2017 and 2016 was $19,198 and $18,569, respectively. Rent expense for the six months ended December 31, 2017 and 2016 was $39,049 and $53,425, respectively.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors.When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2017 Annual Report on Form 10-K for the year ended June 30, 2017 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.
We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation and its wholly owned subsidiaries.
Estimates
Executive Overview
General
General
We are engaged primarily inEvolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its stockholders through the developmentownership, management and productiondevelopment of oil and gas reserves within knownproperties. The Company's long-term goal is to build a diversified portfolio of oil and gas resources utilizing conventional technology with a focus on creating value on a per share basis. In doing so, we depend on a capital structure with low or no leverage, allowing usassets primarily through acquisitions, while seeking opportunities to maintain controland increase production through selective development, production enhancement and other exploitation efforts on its properties.
Our producing assets consist of our assets forinterests in the benefit of our stockholders. Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and a de minimis overriding royalty interest retained in two onshore Texas wells.
By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this ownership helps ensure that the interests of our employees and directors are aligned with our shareholders.
Our strategy is to maximize the value realized by our stockholders from our assets, particularly our core Delhi asset.
stockholders.
Highlights for our SecondFirst Quarter of Fiscal 20182020 and Operations Update
"Current quarter" refers to the three months ended December 31, 2017,September 30, 2019, the Company's secondfirst quarter of fiscal 2018.2020.
"Prior quarter" refers to the three months ended SeptemberJune 30, 2017,2019, the Company's firstfourth quarter of fiscal 2018.2019.
"Year-ago quarter" refers to the three months ended December 31, 2016,September 30, 2018, the Company's secondfirst quarter of fiscal 2017.
2019.
Highlights for the Quarter:
We reported revenues of $11.1 million for the current quarter, an increase of 30% over both the prior and year-ago quarters.
Current quarter net income was $9.9 million, or $0.30 per common share, compared to net income of $0.07 per common share in both the prior and year-ago quarters.Quarter
Net income for the current quarter included a one-time $6.0 million non-cash tax benefit related to passage of the Tax Cuts and Jobs Act of 2017.
Our realized oil price for the current quarter was $57.30 per barrel, the highest quarterly average since the quarter ended June 30, 2015.
We paid our seventeenthtwenty-fourth consecutive quarterly cash dividend on common shares, in the amount of $0.075 per share, and announced an increase in thedeclared our twenty-fifth quarterly dividend rate toof $0.10 per share forpayable on December 31, 2019.
We appointed Jason E. Brown as President and Chief Executive Officer, succeeding Robert S. Herlin who remains non-executive Chairman of the quarter ending March 31, 2018.Board.
We ended the current quarter with $27.6$31.7 million of working capital and remain debt free.
Recorded revenues of $9.2 million for the current quarter, an increase of $3.2 million11.8% decrease from the prior quarter, after paying $2.5and 25.6% lower than the year-ago quarter, primarily due to lower commodity pricing.
Production expenses were $3.1 million, a 13.3% decrease compared to prior quarter, and a 10.7% decrease from the year-ago quarter.
Reported net income of $2.8 million, compared to $3.3 million in common stock dividends.
Projects
Additional propertythe prior quarter and project information is included under Item 1. Business, Item 2. Properties, Notes to$5.8 million in the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2017.
year-ago quarter.
Delhi Field - Enhanced Oil Recovery Project
Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate overriding royalty and mineral interests of 7.2%. This yields a total net revenue interest of 26.2%. The field is operated by Denbury Onshore LLC, a subsidiary of Denbury Resources, Inc. (the "operator").
Net production of oil and NGL averaged 1,910 BOEPD during the quarter which is a decrease of 7% compared to the 2,058 BOEPD during the prior quarter. Gross oil production at Delhi averaged approximately 6,200 BOPD during the quarter, a 3% decrease from the prior quarter. Gross NGL production for quarter was approximately 1,100 BOEPD, down 26% from the prior quarter. Oil production was impacted by seasonal high ambient temperatures during the quarter causing limited CO2
recycle capacity. This resulted in limited capacity to produce high gas/oil ratio wells. Facility modifications resulting in NGL volume uplift in the secondspring were not sustained due to complications caused by the separation of rich gas to a dedicated facility. The operator is reviewing solutions to return to the higher rates seen in the past quarters.
During the current quarter, we incurred $0.6 million on capital projects consisting of fiscal 2018 averaged 7,370 barrels$0.1 million for capital maintenance and $0.5 million primarily for remaining completion costs of a water injection well and a water source well in preparation for Phase V expansion.
In the current quarter, operating revenues were $9.2 million, based on an average realized oil price of $59.32 per day ("BOPD"), or 1,932 BOPD net to our interests, a 6.6% increasebarrel and an average realized NGL price of $11.54 per BOE, resulting in $3.3 million in income from operations. Our realized oil price decreased 8.4% from the prior quarter and a 2.8% decrease from the year-ago quarter. Oil production in the quarter increased as we put additional existing compression capacity in service and experimented with larger choke sizes to boost the injection of CO2oil volumes declined 1.8%. We also had very few days of scheduled and unscheduled facility downtime compared toOur NGL realized price was 24.5% lower than the prior quarter. Lastly, we benefited fromquarter's and volumes decreased 24.9%.
Our NGL price received for our royalty production is burdened by a fixed capital recovery charge, which is mostly offset by our working interest share of such capital recovery that is reflected as a reduction in lease operating expense. The impact of this charge on our NGL royalty revenue is more significant at lower air temperatures, after the high heat of the summer adversely effected productionprice levels.
Gross natural gas liquid ("NGL") sales for this quarter of production were 1,079 barrels of oil equivalent per day ("BOEPD"), or 283 BOEPD net to our interests, up slightly from 1,047 BOEPD in the prior quarter. NGL production rates in the prior quarter were impacted by both planned and unplanned downtime in the field and at the central production facilities. In early August, the plant was shut-in for four days to perform capital upgrades to the inlet of the recycle facility. Results from the NGL plant subsequent to completion of this project have been positive, with the plant operating at or near maximum capacity and efficiency. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane) to increase the purity of the CO2 recycle stream and improve the efficiency of the flood. Over time, this is expected to increase the recovery of crude oil in the field. The plant is also producing significant quantities of higher value NGL's for sale as well as providing methane and ethane feedstock to power the electric turbine.
Production from the NGL plant is transported by truck to a processing plant in East Texas. Under our current marketing contract, we receive market index pricing for each NGL component, based on the processed yield, less transportation and processing fees. There may also be an adjustment for NGL's that do not meet the purchaser's required specifications. The current mix of products contains a large percentage (over 65%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's during the past two quarters has been favorable, with net realized NGL prices averaging approximately 60% of WTI prices. NGL demand often has a seasonal pattern and prices tend to be higher during the cooler months of October through March.
During the extreme cold of January 2018, we experienced two weather-related disruptions to production in the field, including an extended outage at the NGL plant. These issues have been remedied and the field and NGL plant are producing at normal capacity.
Field operating expenses were $14.30 per barrel of oil equivalent ("BOE") in the current quarter compared to $15.06 in the prior quarter. Our total lease operating expensescosts in the Delhi field were $2.9$3.1 million in the current quarter, essentially unchangeddown 13.3% from the prior quarter, and $0.6 million over the year-ago quarter. Ourprimarily due to a 24.3% decrease in purchased CO2 costs increasedvolumes which averaged 69.7 million cubic feet (MMcf) per day compared to $1.3 million ($6.21 per BOE) from $1.1 million ($5.67 per BOE) in the prior quarter. Purchasedquarter's rate of 92.1 MMcf per day. Current quarter CO2 volumes were approximatelypurchase cost of $0.84 per mcf was 8% lower than the same inprevious quarter, reflecting the two periods, but our costs per Mcf increased as a result of higherlower current quarter realized oil prices in the field,price to which are directly tied to the price per Mcf for purchased CO2. cost is linked.
Net income for the quarter was $2.8 million, or $0.08 per diluted share, compared to $3.3 million, or $0.10 per diluted share, in the previous quarter.
Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.1 of our Form 10-K for the year ended June 30, 2019.
Results of Operations
Three Months Ended September 30, 2019 and 2018
Revenues
Compared to the corresponding year-ago period, current period revenues decreased 26% due to 22% lower realized commodity prices together with a 4.2% decrease in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended September 30, 2019 and 2018: |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
Oil and gas production | | | | | | | |
Crude oil revenues | $ | 8,845,504 |
| | $ | 11,397,452 |
| | $ | (2,551,948 | ) | | (22.4 | )% |
NGL revenues | 305,944 |
| | 909,627 |
| | (603,683 | ) | | (66.4 | )% |
Natural gas revenues | 767 |
| | — |
| | 767 |
| | n.m. |
|
Total revenues | $ | 9,152,215 |
| | $ | 12,307,079 |
| | $ | (3,154,864 | ) | | (25.6 | )% |
| | | | | | | |
Crude oil volumes (Bbl) | 149,107 |
| | 158,906 |
| | (9,799 | ) | | (6.2 | )% |
NGL volumes (Bbl) | 26,516 |
| | 24,401 |
| | 2,115 |
| | 8.7 | % |
Natural gas volumes (Mcf) | 356 |
| | — |
| | 356 |
| | n.m. |
|
Equivalent volumes (BOE) | 175,682 |
| | 183,307 |
| | (7,625 | ) | | (4.2 | )% |
| | | | | | | |
Crude oil (BOPD, net) | 1,621 |
| | 1,727 |
| | (106 | ) | | (6.1 | )% |
NGLs (BOEPD, net) | 288 |
| | 265 |
| | 23 |
| | 8.7 | % |
Natural gas (BOEPD, net) | 1 |
| | — |
| | 1 |
| | n.m. |
|
Equivalent volumes (BOEPD, net) | 1,910 |
| | 1,992 |
| | (82 | ) | | (4.1 | )% |
| | | | | | | |
Crude oil price per Bbl | $ | 59.32 |
| | $ | 71.72 |
| | $ | (12.40 | ) | | (17.3 | )% |
NGL price per Bbl | 11.54 |
| | 37.28 |
| | (25.74 | ) | | (69.0 | )% |
Natural gas price per Mcf | 2.15 |
| | — |
| | 2.15 |
| | n.m. |
|
Equivalent price per BOE | $ | 52.10 |
| | $ | 67.14 |
| | $ | (15.04 | ) | | (22.4 | )% |
n. m. Not meaningful.
Production Costs
The $0.4 million decrease in production costs was due to a 9% decrease in other production costs together with a 13% decrease in CO2 costs. The $0.2 million decrease in other production costs was primarily due to lower chemical and fuel gas expenses. |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
CO2 costs (a) | $ | 1,284,767 |
| | $ | 1,483,852 |
| | $ | (199,085 | ) | | (13.4 | )% |
Other production costs | 1,805,322 |
| | 1,974,578 |
| | (169,256 | ) | | (8.6 | )% |
Total production costs | $ | 3,090,089 |
| | $ | 3,458,430 |
| | $ | (368,341 | ) | | (10.7 | )% |
| | | | | | | |
CO2 costs per BOE | $ | 7.31 |
| | $ | 8.09 |
| | $ | (0.78 | ) | | (9.6 | )% |
All other production costs per BOE | 10.28 |
| | 10.78 |
| | (0.50 | ) | | (4.6 | )% |
Production costs per BOE | $ | 17.59 |
| | $ | 18.87 |
| | $ | (1.28 | ) | | (6.8 | )% |
(a) Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per thousand cubic feet (“Mcf”)Mcf, plus sales taxes of 8%approximately 8.5% and transportation costs of $0.20 per Mcf. Our other lease operatingTransportation costs were $1.6 million, down from $1.8 million in the prior quarter.will decline effective January 1, 2020 as per contract terms.
The $0.2 million decrease in total CO2 costs was virtually all due to a lower purchase price per mcf which decreased 13% from the year-ago quarter reflecting the lower realized oil price, while purchased CO2 volumes were flat. 2017 Tax Cuts |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
CO2 costs per mcf | $ | 0.84 |
| | $ | 0.97 |
| | $ | (0.13 | ) | | (13.4 | )% |
CO2 volumes (MMcf per day, gross) | 69.7 |
| | 69.6 |
| | 0.1 |
| | 0.1 | % |
Depletion, Depreciation and Jobs ActAmortization ("DD&A")
On December 22, 2017,DD&A expense was (6.4)% lower compared to the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includessame year-ago period due to a permanent reduction(2.4)% decline in our federal corporate income taxDD&A rate from 34% to 21%. It also provides more favorable tax deductions associatedalong with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ended June 30, 2018 is a blended rate of 27.55%. The permanent reduction4.2% decrease in production volumes in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.
|
| | | | | | | | | | | |
| Three Months Ended December 31, | | Six Months Ended December 31, |
| 2017 | | 2016 | | 2017 | | 2016 |
Income before income taxes | 4,824,637 |
| | 3,668,731 |
| | 7,355,491 |
| | 6,374,682 |
|
Income tax (benefit) provision (a) | (5,052,211 | ) | | 1,361,097 |
| | (4,661,889 | ) | | 2,250,273 |
|
Effective tax rate (a) | (105 | )% | | 37 | % | | (63 | )% | | 35 | % |
|
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
DD&A of proved oil and gas properties | $ | 1,417,754 |
| | $ | 1,516,742 |
| | $ | (98,988 | ) | | (6.5 | )% |
Depreciation of other property and equipment | 2,322 |
| | 4,143 |
| | (1,821 | ) | | (44.0 | )% |
Amortization of intangibles | 3,391 |
| | 3,391 |
| | — |
| | — | % |
Accretion of asset retirement obligations | 26,287 |
| | 24,184 |
| | 2,103 |
| | 8.7 | % |
Total DD&A | $ | 1,449,754 |
| | $ | 1,548,460 |
| | $ | (98,706 | ) | | (6.4 | )% |
| | | | | | | |
Oil and gas DD&A rate per BOE | $ | 8.07 |
| | $ | 8.27 |
| | $ | (0.20 | ) | | (2.4 | )% |
General and Administrative Expenses
(a) The income tax provision for the three months and six months ended December 31, 2017 includes a one-time non-cash benefit of approximately $6.0 million for the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. This adjustment results in a negative effective tax rate (benefit) for these periods.
Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation of our income tax expense were approximately 21% and 37%Expenses for the three months ended December 31, 2017 and 2016, respectively. Including the adjustment for the $6.0September 30, 2019 increased slightly by 2.5%, to $1.3 million discrete benefit resulting from the revaluation of our deferredsame year-ago quarter, primarily due to higher non-cash stock based compensation expenses in the current period, offset by normal variations in professional services expenses.
Other Income and Expenses
Other income tax liabilities,and expense (net) decreased due primarily to the effective rate for the quarter ended December 31, 2017 was a tax benefit of (105)% of income before income taxes.Enduro breakup fee received during August 2018. |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
Enduro transaction breakup fee | — |
| | 1,100,000 |
| | (1,100,000 | ) | | (100.0 | )% |
Interest and other income | 66,129 |
| | 46,571 |
| | 19,558 |
| | 42.0 | % |
Interest expense | (29,345 | ) | | (29,345 | ) | | — |
| | — | % |
Total other income, net | $ | 36,784 |
| | $ | 1,117,226 |
| | $ | (1,080,442 | ) | | (96.7 | )% |
For the six months ended December 31, 2017 and 2016 the effective rates used in the calculation of ourNet Income
Net income tax expense were approximately 20% and 35% , respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.
Excluding the impact of the $6.0 million deferred tax adjustment, the effective tax ratesavailable to common stockholders for the three months
ended September 30, 2019 decreased $3.0 million, or 52%, to $2.8 million compared to the same year-ago quarter primarily due to the aforementioned operating variances and
six months ended December 31, 2017 were lower than the
corresponding prior periods as a result ofone-time breakup fee collected in the
lower statutory tax rate and higher utilization of percentage depletion in excess of basis during the current year.year-ago quarter. |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | | | | |
| 2019 | | 2018 | | Variance | | Variance % |
Income before income taxes | 3,310,803 |
| | 7,112,153 |
| | (3,801,350 | ) | | (53.4 | )% |
Income tax provision | 517,983 |
| | 1,316,352 |
| | (798,369 | ) | | (60.7 | )% |
Net income available to common stockholders | $ | 2,792,820 |
| | $ | 5,795,801 |
| | $ | (3,002,981 | ) | | (51.8 | )% |
Income tax provision as a percentage of income before income taxes | 16 | % | | 19 | % | | | | |
Liquidity and Capital Resources
We had $25.7 million and $23.0$31.4 million in cash and cash equivalents at December 31, 2017September 30, 2019 and $31.5 million of cash and cash equivalents at June 30, 2017, respectively.2019.
In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50.0$50 million. The Facility had $10.0$40 million of undrawn borrowing base availability on December 31, 2017 and JuneSeptember 30, 2017, respectively. Effective February 1, 2018,2019. Under the Facility the borrowing base shall be determined semiannually as of May 15 and availability under the Facility was expanded to $40.0 million.November 15. There have been no borrowings under the Facility, which matures on April 11, 20192021, and it is secured by substantially all of the Company’s assets.
During the current quarter, the bank performed its periodic redetermination of borrowing base and confirmed our elected amount of $40 million. Our next scheduled determination will occur next spring.
Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants that require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than $40$50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of December 31, 2017,September 30, 2019, the Company was in compliance with all covenants contained in the Facility.
During the sixthree months ended December 31, 2017,September 30, 2019, we funded our operations, capital expenditures and cash dividends with cash generated from operations and ourresulting in a decrease of $0.1 million in cash, balance increased $2.7impacted by $1.3 million during that period.spent on repurchasing shares under the buyback program. As of December 31, 2017,September 30, 2019, our working capital was $27.6$31.7 million, an increasea decrease of $4.2$0.8 million over working capital of $23.4$32.4 million at June 30, 2017.
2019.
We have historically funded our operations through cash from operations and working capital. Our primary source of cash is the sale of oil and natural gas liquids production. A portion of these cash flows are used to fund our capital expenditures. While we expect to continue to expend capital to further develop the Delhi field, we and the operator have flexibility as to when this capital is spent. The Company expects to manage future development activities in the Delhi field within the boundaries of its operating cash flow and existing working capital.
We may choose to evaluate and pursueare pursuing new growth opportunities through acquisitions or other transactions. WeIn addition to our cash on hand, we have access to at least $40 million of undrawn elected borrowing base availability under our senior secured credit facility if required.facility. In addition we have an effective shelf registration statement with Securities and Exchange Commission under which we may issue up to $500 million of new debt or equity securities. IfAs we choose to pursue new growth opportunities, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do soissue additional equity at this time.
Our other significant useOn November 1, 2019, and effective as of October 1, 2019, our wholly-owned subsidiary, Evolution Petroleum West, Inc., a Delaware corporation, purchased a 23.51% non-operating working interest and a 19.70% revenue interest in the Hamilton Dome field located in Hot Springs County, Wyoming, from entities owned or controlled by Merit Energy Company ("Merit") of Dallas, Texas. The consideration to Merit consisted of $9.5 million in cash and our assumption of asset retirement obligations. Merit will continue to operate the field and Merit retains the majority ownership of the balance of the working interest.
The field was discovered in 1918 and has been on production for 100 years producing over 160 million barrels of oil. We acquired approximately 450 barrels of expected net oil production per day, which should add approximately 23% to our daily production, and represent a 30% increase to our proved reserves. We expect operating expense per barrel to be somewhat higher than Delhi and the realized oil price lower; however we believe that improving pipeline capacity to the region within the next several years will result in a stronger market. As reserves are virtually all proved developed producing, capital expenditures are expected to be nominal. This asset is expected to contribute to our overall profitability and further support our dividend moving forward.
In addition to our on-going cash dividend program.program, during September 30, 2019, the Company repurchased $1.3 million of common shares under the stock buyback program approved in May 2015. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid seventeentwenty-four consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of our operating and capital requirements through cash dividends and potential repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate. In February 2018,On November 4 , 2019, the Board declared an increase in the next quarterly common stock dividend from $0.075 per share toof $0.10 per share, effective with the dividend payment in March 2018.which will be paid on December 31, 2019 to stockholders of record on December 16, 2019. The Board reviews
the quarterly dividend rate in light of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing of further expansion of Delhi development and other potential growth opportunities.
Capital Budget - Delhi Field
During the six months ended December 31, 2017,current quarter, we incurred $1.4$0.6 million on capital projects consisting of $0.1 million for capital expenditures at Delhi. Thismaintenance and $0.5 million for remaining completion costs of a water injection well and a water source well in preparation for Phase V expansion.
The current expectation for net capital spending includedfor the remainder of fiscal 2020 is approximately $3.0 million, which includes $0.4 million for the NGL plant filter/separator project, $0.7 million for conformance and capital upgrades to the recycle plant, $0.5maintenance, and $1.9 million for Phase V infrastructure, $0.4development expected later in the fiscal year. We believe that the operator will continue this development and have also budgeted $3.0 million for Phase V completion in fiscal 2021. We anticipate funding for our share of capital expenditure at Delhi to be met from cash flows from operations.
Our proved undeveloped reserves at June 30, 2019 included 1,583 MBOE of reserves and $8.6 million of future development costs associated with Phase V development in the eastern portion of the field. The timing of Phase V development is dependent in part on the results and CO2 conformance projects and $0.1 million for other capital expenditures.
A twelve-wellrequirements of the infill drilling programprogram. The timing of such development is also dependent, in part, on the Delhi field has been approvedoperator's available funds and is planned to commence during the quarter ended March 31, 2018. The infill program has a revised estimated net costcapital spending plans and priorities within its portfolio of $4.7 million, the majority of which is expected to be incurred in the remainder of the current fiscal year. The program consists of five new CO2 injection wells and seven new production wells and targets productive oil zones which we believe are not being swept effectively by the current CO2 flood. It is expected to both add production and increase ultimate recoveries above the current developed producing oil reserves. The operator estimates it will take up to five months to drill and complete all the wells.
We have also approved additional net capital expenditures for fiscal 2018 totaling $2.8 million for water injection, flowlines and other infrastructure projects in preparation for the Phase V pattern development. Approximately $0.5 million of these costs have been incurred as of December 31, 2017. In addition,properties. At present, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately atbegin this time, but are not expected to be material todevelopment in our financial position.fiscal year 2020.
Funding for our anticipated capital expenditures at Delhi over the nextfor our fiscal year2020 is expected to be met from cash flows from operations and current working capital.
Overview of Cash Flow Activities
NetThe table below compares a summary of our condensed consolidated statements of cash flows for three months ended September 30, 2019 and 2018 presented in the consolidated condensed financial statements in Item 1, Part I of this report on Form 10-Q.
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | |
Increases (Decreases) in Cash: | 2019 | | 2018 | | Difference |
| (In Millions) |
Net cash provided by operating activities | $ | 5.0 |
| | $ | 7.7 |
| | $ | (2.6 | ) |
Net cash used in investing activities | (0.5 | ) | | (3.1 | ) | | 2.6 |
|
Net cash used in financing activities | (4.7 | ) | | (3.4 | ) | | (1.3 | ) |
| $ | (0.1 | ) | | $ | 1.2 |
| | $ | (1.3 | ) |
Cash provided by operating activities from operations was $9.1in the current year period decreased $2.6 million and $5.9compared to the same year-ago period due to a $3.0 million for the six months ended December 31, 2017 and 2016, respectively. The $3.2decrease in cash provided by net income together with $0.3 million decrease in cash provided by non-cash expenses, partially offset by $0.7 million increase in cash provided by operations between these two periods resulted from $7.9 million of higher net income and a $1.2 million increase in cash provided bycurrent operating assets and liabilities partially offset by a $5.9 million decrease in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations. This decrease includes a $6.0 million one-time adjustment of our deferred income tax liability to the lower corporate tax rate under the 2017 Tax Cuts and Jobs Act.by.
Net cashCash used in investing activities was $1.0decreased $2.6 million and $8.3 million for the six months ended December 31, 2017 and 2016, respectively. The decrease in cash outflows was primarily due to $7.0 million of lower capital expenditures together with a $0.3 million declineexpenditure disbursements in derivative settlement payments.the fiscal 2020 period while completion of the infill project was underway.
Net cashCash used by financing activities for the six months ended December 31, 2017 and 2016 was $5.4increased $1.3 million and $12.4 million, respectively. The $7.1 million decrease in cash used was principally due to $7.9 million disbursedcommon stock repurchases in the prior fiscal to redeem our preferred stock, $0.3 million of pre-redemption preferred dividend payments, and a $0.1 million decline in treasury stock purchases, partially offset by an increase of $1.2 million in common share dividends paid as a result of increases in dividend rates per share.
Full Cost Pool Ceiling Test and Proved Undeveloped Reserves
As of December 31, 2017, our capitalized costs of oil and gas properties were substantially below the full cost valuation ceiling. We do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarters of fiscal 2018. However, persistent and substantially lower oil prices would have an effect on the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and could adversely impact our ceiling tests in future quarters. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to (the full cost valuation “ceiling”): the estimated future net cash flows from proved oil and gas reserves, discounted at 10%; plus the cost of any properties not being amortized; plus the lower of cost or fair value of unproved properties included in costs being amortized; less the income tax effect related to the differences between the book and tax basis of the properties. If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our petroleum products during the twelve month period ending with the balance sheet date. If commodity prices drop below the average from the past twelve months, future ceiling test calculations would be adversely affected. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future.
Our proved undeveloped reserves at June 30, 2017 included 544 MBOE of reserves and $3.2 million of future development costs associated with a planned infill drilling program and 1,564 MBOE of reserves and $10.9 million of future development costs associated with the Phase V development in the eastern portion of the field. The objective of the infill drilling program is to increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The project includes both acceleration of production and an increase in ultimate reserve recovery and has been recorded as a proved undeveloped project. The infill project, which was increased from eight wells to twelve wells subsequent to the date of the reserve report, is expected to begin in the thirdfirst quarter of fiscal 2018. The timing2020 through an authorized stock buyback program.
Critical Accounting Policies and Estimates
See our Critical Accounting Policies and Estimates as disclosed within Item 7. Management's Discussion and Analysis of our Phase V development is dependentFinancial Condition and Results of Operations in part on the results2019 Form 10-K. For recently adopted and CO2 requirement of the infill program. At present, we expect to begin this development in calendar 2019.
Three Months Ended December 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:
|
| | | | | | | | | | | | | | |
| Three Months Ended December 31, | | | | |
| 2017 | | 2016 | | Variance | | Variance % |
Oil and gas production: | | | | | | | |
Crude oil revenues | $ | 10,185,635 |
| | $ | 8,529,817 |
| | $ | 1,655,818 |
| | 19.4 | % |
NGL revenues | 881,276 |
| | — |
| | 881,276 |
| | n.m. |
|
Total revenues | $ | 11,066,911 |
| | $ | 8,529,817 |
| | $ | 2,537,094 |
| | 29.7 | % |
| | | | | | | |
Crude oil volumes (Bbl) | 177,767 |
| | 182,815 |
| | (5,048 | ) | | (2.8 | )% |
NGL volumes (Bbl) | 26,033 |
| | — |
| | 26,033 |
| | n.m. |
|
Equivalent volumes (BOE) | 203,800 |
| | 182,815 |
| | 20,985 |
| | 11.5 | % |
| | | | | | | |
Crude oil (BOPD, net) | 1,932 |
| | 1,987 |
| | (55 | ) | | (2.8 | )% |
NGLs (BOEPD, net) | 283 |
| | — |
| | 283 |
| | n.m. |
|
Equivalent volumes (BOEPD, net) | 2,215 |
| | 1,987 |
| | 228 |
| | 11.5 | % |
| | | | | | | |
Crude oil price per Bbl | $ | 57.30 |
| | $ | 46.66 |
| | $ | 10.64 |
| | 22.8 | % |
NGL price per Bbl | 33.85 |
| | — |
| | 33.85 |
| | n.m. |
|
Equivalent price per BOE | $ | 54.30 |
| | $ | 46.66 |
| | $ | 7.64 |
| | 16.4 | % |
| | | | | | | |
CO2 costs | $ | 1,265,582 |
| | $ | 1,041,741 |
| | $ | 223,841 |
| | 21.5 | % |
All other lease operating expenses | 1,648,930 |
| | 1,250,680 |
| | 398,250 |
| | 31.8 | % |
Production costs | $ | 2,914,512 |
| | $ | 2,292,421 |
| | $ | 622,091 |
| | 27.1 | % |
Production costs per BOE | $ | 14.30 |
| | $ | 12.54 |
| | $ | 1.76 |
| | 14.0 | % |
CO2 volumes (MMcf per day, gross) | 69.7 |
| | 67.0 |
| | 2.7 |
| | 4.0 | % |
| | | | | | | |
Oil and gas DD&A (a) | $ | 1,626,324 |
| | $ | 1,299,813 |
| | $ | 326,511 |
| | 25.1 | % |
Oil and gas DD&A per BOE | $ | 7.98 |
| | $ | 7.11 |
| | $ | 0.87 |
| | 12.2 | % |
n.m. Not meaningful.
(a) Excludes $7,544and $7,697 of other depreciation and amortization expense for the three months ended December 31, 2017 and 2016, respectively.
Net Income Available to Common Stockholders. During the three months ended December 31, 2017, we generated net income of $9.9 million, or $0.30 per diluted share, on total revenues of $11.1 million. This compares to net income of $2.3 million, or $0.07 per diluted share, on revenues of $8.5 million for the year-ago quarter. The $7.6 million earnings increase reflects a $2.5 million revenue increase, a $6.4 million decline in income taxes primarily attributable to the impact of the 2017 Tax Cuts and Jobs Act, partially offset by $1.4 million of higher operating expenses.
Oil and Gas Revenues. Revenues increased 30% to $11.1 million as a result of a 11.5% increase in production volumesrecently issued accounting pronouncements from the year-ago quarter, together with a 16% increase in realized oil and NGL prices from $46.66 per equivalent barrel to $54.30 per equivalent barrel in the current quarter. AllFinancial Accounting Standards Board, please see Note 2 – Summary of our revenues for the current and year-ago quarters came from the Delhi field. Net Delhi oil production volumes of 1,932 BOPD decreased 55 BOPD from the year-ago quarter, as a number of highly successful conformance and production enhancement operations in the prior year stabilized at lower rates in the current quarter. Net NGL production averaged 283 BOEPD in the current quarter, at an average sales price of $33.85 per barrel. There were no NGL sales in the year-ago quarter as NGL plant production began in January 2017.
Production Costs. Production costs for the current quarter were $2.9 million, a $0.6 million, or 27%, increase from the year-ago quarter, primarily due to to higher CO2 costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO2 costs increased $0.2 million, or 21%, due to a higher purchase cost per Mcf, which is derived from the realized field oil price, together with 4% increase in purchase volumes. Average gross purchased CO2 volumes increased from 67.0 MMcf per day in the year-ago quarter to 69.7 MMcf per day for the current quarter. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.4 million, or 32%, from the year-ago quarter. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current quarter were $14.30 per BOE on total production volumes, compared to $15.06 per BOE in the year-ago quarter.
Calculated solely on our Delhi working interest volumes, production costs were $18.75 per BOE, of which $8.55 per BOE was CO2 cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses increased $0.4 million, or 34%, to $1.7 million for the three months ended December 31, 2017 as a result of $0.2 million of higher non-cash stock compensation expense, $0.1 million for litigation costs and $0.1 million for due diligence costs associated with property evaluations.
Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.3 million, or 25%, to $1.6 million for the current quarter compared to the year-ago period primarily as a result of higher full cost amortization, reflecting an 11% increase in production to 203,800 BOE, together with a 12% higher amortization rate of $7.98 per BOE. The higher rate is principally due to increased development costs.
Six Months Ended December 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:
|
| | | | | | | | | | | | | | |
| Six Months Ended December 31, | | | | |
| 2017 | | 2016 | | Variance | | Variance % |
Oil and gas production: | | | | | | | |
Crude oil revenues | $ | 18,014,890 |
| | $ | 16,123,672 |
| | $ | 1,891,218 |
| | 11.7 | % |
NGL revenues | 1,589,892 |
| | 89 |
| | 1,589,803 |
| | n.m. |
|
Natural gas revenues | — |
| | (4 | ) | | 4 |
| | n.m. |
|
Total revenues | $ | 19,604,782 |
| | $ | 16,123,757 |
| | $ | 3,481,025 |
| | 21.6 | % |
| | | | | | | |
Crude oil volumes (Bbl) | 344,504 |
| | 360,817 |
| | (16,313 | ) | | (4.5 | )% |
NGL volumes (Bbl) | 51,279 |
| | 4 |
| | 51,275 |
| | n.m. |
|
Natural gas volumes (Mcf) | — |
| | 16 |
| | (16 | ) | | n.m. |
|
Equivalent volumes (BOE) | 395,783 |
| | 360,824 |
| | 34,959 |
| | 9.7 | % |
| | | | | | | |
Crude oil (BOPD, net) | 1,872 |
| | 1,961 |
| | (89 | ) | | (4.5 | )% |
NGLs (BOEPD, net) | 279 |
| | — |
| | 279 |
| | n.m. |
|
Natural gas (BOEPD, net) | — |
| | — |
| | — |
| | n.m. |
|
Equivalent volumes (BOEPD, net) | 2,151 |
| | 1,961 |
| | 190 |
| | 9.7 | % |
| | | | | | | |
Crude oil price per Bbl | $ | 52.29 |
| | $ | 44.69 |
| | $ | 7.60 |
| | 17.0 | % |
NGL price per Bbl | 31.00 |
| | 22.25 |
| | 8.75 |
| | 39.3 | % |
Natural gas price per Mcf | — |
| | (0.25 | ) | | 0.25 |
| | n.m. |
|
Equivalent price per BOE | $ | 49.53 |
| | $ | 44.69 |
| | $ | 4.84 |
| | 10.8 | % |
| | | | | | | |
CO2 costs | $ | 2,353,843 |
| | $ | 2,119,874 |
| | $ | 233,969 |
| | 11.0 | % |
All other lease operating expenses | 3,452,255 |
| | 2,517,188 |
| | 935,067 |
| | 37.1 | % |
Production costs | $ | 5,806,098 |
| | $ | 4,637,062 |
| | $ | 1,169,036 |
| | 25.2 | % |
Production costs per BOE | $ | 14.67 |
| | $ | 12.85 |
| | $ | 1.82 |
| | 14.2 | % |
| | | | | | | |
CO2 volumes (MMcf per day, gross) | 69.5 |
| | 70.4 |
| | (0.9 | ) | | (1.3 | )% |
| | | | | | | |
Oil and gas DD&A (a) | $ | 3,137,205 |
| | $ | 2,565,450 |
| | $ | 571,755 |
| | 22.3 | % |
Oil and gas DD&A per BOE | $ | 7.93 |
| | $ | 7.11 |
| | $ | 0.82 |
| | 11.5 | % |
n.m. Not meaningful.
(a) Excludes $15,206and $15,499 of other depreciation and amortization expense for the six months ended December 31, 2017 and 2016, respectively.
Net Income Available to Common Stockholders. During the six months ended December 31, 2017, we generated net income of $12.0 million, or $0.36 per diluted share, on total revenues of $19.6 million. This compares to net income of $2.9 million, or $0.09 per diluted share, on revenues of $16.1 million for the six months ended December 31, 2016. The $9.1 million earnings increase reflects higher revenues of $3.5 million, an income tax decrease of $6.9 million primarily attributable to the impact of Tax Cuts and Jobs Act, and a $1.2 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $2.5 million of higher operating expenses.
Oil and Gas Revenues. Revenues increased 22% to $19.6 million as a result of a 10% increase in production volumes over the prior year period, together with a 11% increase in realized prices from $44.69 per equivalent barrel to $49.53 per equivalent barrel. All of our revenues in the current fiscal year came from the Delhi field, as well as virtually all of our revenues from the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD from the prior year period. Net NGL production averaged 279 BOEPD, at an average price of $31.00 per barrel. There were no NGL sales in the year-ago period as NGL plant production began in January 2017.
Production Costs. Production costs for the current year period were $5.8 million, a $1.2 million, or 25%, increase from the same period a year ago, primarily due to higher CO2 costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO2 costs increased $0.2 million, or 11%, due to higher purchase cost per Mcf, which is derived from the realized field oil price, partially offset by a slight 1% decline in purchase volumes. Average gross purchased CO2 volumes decreased from 70.4 MMcf per day in the year-ago period to 69.5 MMcf per day for the current year. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.9 million, or 37%, from the year-ago period. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current period were $14.67 per BOE on total production volumes, compared to $12.85 in the prior year period.
Calculated solely on our Delhi working interest volumes, production costs were $19.24 per BOE, of which $8.19 per BOE was CO2 cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses increased $0.8 million, or 31%, to $3.2 million for the six months ended December 31, 2017. The increase in expense included $0.4 million of non-cash stock-based compensation expense, $0.1 million of severance costs, $0.1 million of litigation expense, $0.1 million of due diligence costs associated with property evaluations, and $0.1 million of higher board of director expenses.
Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.6 million, or 22%, to $3.2 million for the current period compared to the year-ago period primarily due to higher full cost amortization, reflecting a 10% increase in production to 395,783 BOE, together with a 12% higher amortization rate of $7.93 per BOE. The higher rate is principally due to increased development costs.
Other Economic Factors
Inflation. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services impact our lease operating expenses and our capital expenditures. During fiscal 2018 to date, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties. General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas exceeds demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward. While we realized higher average oil prices in the quarter than any period since the quarter ended June 30, 2015, there can be no assurance that such prices will continue to prevail or trend upward.
Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do occasionally experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes. We have also experienced adverse impacts on our production from very high summer temperatures and extremely cold winter weather.
Off Balance Sheet Arrangements
The Company had no off-balance sheet arrangements to report for the quarter ended December 31, 2017.Significant Accounting Policies herein.
ITEMItem 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSQuantitative and Qualitative Disclosures About Market Risks
Information about market risks for the three months ended December 31, 2017,September 30, 2019, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2017.2019.
Commodity Price Risk
Our most significant market risk is the pricing for crude oil and NGL's. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, our revenues and cash flow would significantly decline. In addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. We may use derivative instruments to manage our exposure to commodity price risk from time to time based on our assessment of such risk.
Interest Rate Risk
We currently have only a small exposure to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
ITEMItem 4. CONTROLS AND PROCEDURESControls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2017September 30, 2019 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended December 31, 2017,September 30, 2019, we have determined there has been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are involved in certain legal proceedings that are described in our Annual Report on Form 10-K for the year ended June 30, 2017 in Part I. Item 3. “Legal Proceedings” and Note 18 — Commitments and Contingencies under Part II. Item 8. “Financial Statements.” Material developments in the status of those proceedings during the quarter ended December 31, 2017 are described in Part I. Item 1. "Financial Information" under Note 14 — Commitments and Contingencies in this Quarterly Report and incorporated herein by reference. We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position.Legal Proceedings
None.
ITEMItem 1A. RISK FACTORSRisk Factors
Our Annual Report on Form 10-K for the year ended June 30, 20172019 includes a detailed description 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, 2017.2019.
ITEMItem 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDSUnregistered Sales of Equity Securities and Use of Proceeds
During the quarter ended December 31, 2017, the Company did not sell any equity securities that were not registered under the Securities Act.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2017,September 30, 2019, the Company purchased shares of common stock in the open market under its share repurchase program announced in May 2015 and also received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and contingent restricted stock. During this quarter, the Company did not purchase any common stock in the open market under the previously announced share repurchase program. The table below summarizes information about the Company's purchases of its equity securities during the quarter ended December 31, 2017.September 30, 2019. |
| | | | | | | | |
Period | | (a) Total Number of Shares Purchased (1) | | (b) Average Price Paid per Share(1) | | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
October 2017 | | 2,471 | | $7.03 | | Not applicable | | $3.4 million |
November 2017 | | 29,001 | | $7.20 | | Not applicable | | $3.4 million |
December 2017 | | 8,262 | | $7.10 | | Not applicable | | $3.4 million |
Total | | 39,734 | | $7.17 | | Not applicable | | $3.4 million |
|
| | | | | | | | |
Period | | (a) Total Number of Shares Purchased (1) | | (b) Average Price Paid per Share(1) | | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | | (d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
July 2019 | | — | | $— | | Not applicable | | $3.4 million |
August 2019 | | 167,805 | | $5.94 | | Not applicable | | $2.4 million |
September 2019 | | 63,571 | | $5.76 | | Not applicable | | $2.1 million |
Total | | 231,376 | | $5.89 | | Not applicable | | $2.1 million |
(1)During the current quarter the Company received 8,939 shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.
(2)On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled.
ITEMItem 3. DEFAULTS UPON SENIOR SECURITIESDefaults Upon Senior Securities
Not applicable.
ITEMItem 4. MINE SAFETY DISCLOSURESMine Safety Disclosures
Not applicable.
ITEMItem 5. OTHER INFORMATIONOther Information
None.
ITEMItem 6. EXHIBITSExhibits
A. Exhibits
|
| | | |
4.1 |
| | |
4.2 |
| | |
10.1 |
| | |
31.1 |
| | |
31.2 |
| | |
32.1 |
| | |
32.2 |
| | |
101.INS |
| | XBRL Instance Document |
101.SCH |
| | XBRL Taxonomy Extension Schema Document |
101.CAL |
| | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF |
| | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB |
| | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE |
| | XBRL Taxonomy Extension Presentation Linkbase Document |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EVOLUTION PETROLEUM CORPORATION
(Registrant)
|
| | | |
| | By: | /s/ RANDALL D. KEYSDAVID JOE |
| | | Randall D. KeysDavid Joe |
| | | Senior Vice President, and Chief ExecutiveFinancial Officer and |
| | | Treasurer |
Date: FebruaryNovember 8, 20182019 | | |