Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
| | |
Nevada | 41-1781991 | |
(State or other jurisdiction of | | (IRS Employer Identification No.) |
1155 Dairy Ashford Road, Suite 425, Houston, Texas77079
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| | | | |
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:
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:
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 definitionsdefinition of “large"large accelerated filer,” “accelerated filer,” “smallerfiler", "accelerated filer", "smaller reporting company,”company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| | | | | | | |
| | | | | | | |
Large accelerated filer | ☐ | Accelerated filer | ☒ | Non-accelerated filer | ☐ | Smaller reporting company | ☒ |
| |||||||
| | | | | Emerging growth company | ||
☐ |
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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes:
At May 3, 2024, 33,357,632 shares outstanding of the registrant’s common stock,Registrant’s Common Stock, $0.001 par value $0.001, asper share, were outstanding.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
| | ||
2 | |||
| . | 4 | ||
4 | |||
| 4 | ||
| 5 | ||
| 6 | ||
| 7 | ||
| 8 | ||
Management’s Discussion and Analysis of Financial Condition and Results of Operations | 25 | ||
40 | |||
40 | |||
41 | |||
41 | |||
41 | |||
41 | |||
42 | |||
42 | |||
42 | |||
42 | |||
| |||
43 | |||
We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and Subsidiariesunless the context otherwise requires, its wholly-owned subsidiaries.
1
| December 31, 2017 | June 30, 2017 | ||||||
| Assets | |||||||
| Current assets | |||||||
| Cash and cash equivalents | $ | 25,743,497 | $ | 23,028,153 | |||
| Receivables | 4,078,153 | 2,726,702 | |||||
| Prepaid expenses and other current assets | 824,048 | 387,672 | |||||
| Total current assets | 30,645,698 | 26,142,527 | |||||
| Oil and natural gas property and equipment, net (full-cost method of accounting) | 60,093,807 | 61,790,068 | |||||
| Other property and equipment, net | 32,265 | 40,689 | |||||
| Total property and equipment | 60,126,072 | 61,830,757 | |||||
| Other assets | 260,468 | 295,384 | |||||
| Total assets | $ | 91,032,238 | $ | 88,268,668 | |||
| Liabilities and Stockholders’ Equity | |||||||
| Current liabilities | |||||||
| Accounts payable | $ | 2,400,202 | $ | 1,994,255 | |||
| Accrued liabilities and other | 660,467 | 724,639 | |||||
| Total current liabilities | 3,060,669 | 2,718,894 | |||||
| Long term liabilities | |||||||
| Deferred income taxes | 10,580,381 | 15,826,291 | |||||
| Asset retirement obligations | 1,297,028 | 1,253,628 | |||||
| Total liabilities | 14,938,078 | 19,798,813 | |||||
| Commitments and contingencies (Note 14) | |||||||
| Stockholders’ equity | |||||||
| 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 | |||||
| Additional paid-in capital | 41,538,133 | 40,961,957 | |||||
| Retained earnings | 34,522,856 | 27,474,811 | |||||
| Total stockholders’ equity | 76,094,160 | 68,469,855 | |||||
| Total liabilities and stockholders’ equity | $ | 91,032,238 | $ | 88,268,668 | |||
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. All statements, except for statements of historical fact, are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. 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, which may include, but are not limited to, the following:
| ● | our expectations of plans, strategies and objectives, including anticipated development activity and capital spending; |
| ● | our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength; |
| ● | the benefits of our multi-basin portfolio, including operational and commodity flexibility; |
| ● | our ability to maximize cash flow and the application of excess cash flows to reduce long-term debt, pay dividends and repurchase shares pursuant to our share repurchase program; |
| ● | estimates of our oil, natural gas and natural gas liquids (“NGLs”) production and commodity mix; |
| ● | anticipated oil, natural gas and NGL prices; |
| ● | anticipated drilling and completions activity; |
| ● | estimates of our oil, natural gas and NGL reserves and recoverable quantities; |
| ● | our ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles; |
| ● | limitations on our ability to obtain funding based on environmental, social, and corporate governance (“ESG”) performance; |
| ● | future interest expense; |
| ● | our ability to manage debt and financial ratios, finance growth and comply with financial covenants; |
| ● | the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical sales locations hedged; |
| ● | the impact of changes in federal, state, provincial and local, rules and regulations; |
| ● | anticipated compliance with current or proposed environmental requirements, including the costs thereof; |
| ● | the possible impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives; |
| ● | adequacy of provisions for abandonment and site reclamation costs; |
| ● | our operational and financial flexibility, discipline and ability to respond to evolving market conditions; |
| ● | the declaration and payment of future dividends and any anticipated repurchase of our outstanding common shares; |
| ● | the adequacy of our provision for taxes and legal claims; |
| ● | our ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses; |
| ● | our competitiveness relative to our peers, including with respect to capital, materials, people, assets and production; |
| ● | oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs; |
| ● | the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment; |
| ● | adverse weather events; |
| ● | anticipated staffing levels; |
| ● | anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and |
| ● | the possible impact of accounting and tax pronouncements, rule changes and standards. |
2
Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause actual events or results to differ materially and/or adversely from those expressed or implied, which include, but are not limited to, the following assumptions:
| ● | future commodity prices and basis differentials; |
| ● | our ability to access credit facilities and shelf prospectuses; |
| ● | assumptions contained in our corporate guidance; |
| ● | the availability of attractive commodity or financial hedges and the enforceability of risk management programs; |
| ● | expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements; |
| ● | access to adequate gathering, transportation, processing and storage facilities; |
| ● | assumed tax, royalty and regulatory regimes; |
| ● | expectations and projections made in light of, and generally consistent with, our historical experience and our perception of historical industry trends; and |
| ● | the other assumptions contained herein. |
Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents incorporated herein by reference (if any), are not exhaustive. Although we believe the expectations represented by our forward-looking statements are reasonable based on the information available to us as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct.
When considering any forward-looking statement, the reader 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, natural gas and NGLs, operating risks and other risk factors as described under the Risk Factors section of our previously filed Annual Report on Form 10-K for the fiscal year ended June 30, 2023, as well as the other disclosures contained herein, therein, and as also may be described from time to time in future reports we file with the Securities and Exchange Commission. 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. Readers are advised, however, to review any further disclosures we make on related subjects in our filings with the Securities and Exchange Commission.
3
Part I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
| | | | | | |
|
| March 31, 2024 |
| June 30, 2023 | ||
Assets | | |
| | |
|
Current assets | | |
| | |
|
Cash and cash equivalents | | $ | 3,067 | | $ | 11,034 |
Receivables from crude oil, natural gas, and natural gas liquids revenues | | | 13,368 | | | 7,884 |
Derivative contract assets | | | 347 | | | — |
Prepaid expenses and other current assets | | | 6,275 | | | 2,277 |
Total current assets | | | 23,057 | | | 21,195 |
Property and equipment, net of depletion, depreciation, and impairment | | |
| | | |
Oil and natural gas properties, net—full-cost method of accounting, of which none were excluded from amortization | | | 142,157 | | | 105,781 |
| | | | | | |
Other assets | | | 1,318 | | | 1,341 |
Total assets | | $ | 166,532 | | $ | 128,317 |
Liabilities and Stockholders' Equity | | |
| | | |
Current liabilities | | |
| | | |
Accounts payable | | $ | 8,096 | | $ | 5,891 |
Accrued liabilities and other | | | 5,985 | | | 6,027 |
Derivative contract liabilities | | | 1,410 | | | — |
State and federal taxes payable | | | — | | | 365 |
Total current liabilities | | | 15,491 | | | 12,283 |
Long term liabilities | | |
| | | |
Senior secured credit facility | | | 42,500 | | | — |
Deferred income taxes | | | 6,927 | | | 6,803 |
Asset retirement obligations | | | 18,079 | | | 17,012 |
Operating lease liability | | | 79 | | | 125 |
Total liabilities | | | 83,076 | | | 36,223 |
Commitments and contingencies (Note 10) | | | | | | |
Stockholders' equity | | |
| | | |
Common stock; par value $0.001; 100,000,000 shares authorized: issued and | | | | | | |
outstanding 33,359,854 and 33,247,523 shares as of March 31, 2024 | | | | | | |
and June 30, 2023, respectively | | | 33 | | | 33 |
Additional paid-in capital | | | 40,652 | | | 40,098 |
Retained earnings | | | 42,771 | | | 51,963 |
Total stockholders' equity | | | 83,456 | | | 92,094 |
Total liabilities and stockholders' equity | | $ | 166,532 | | $ | 128,317 |
See accompanying notes to unaudited condensed consolidated condensed financial statements.
4
| Three Months Ended December 31, | Six Months Ended December 31, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Revenues | |||||||||||||||
| Crude oil | $ | 10,185,635 | $ | 8,529,817 | $ | 18,014,890 | $ | 16,123,672 | |||||||
| Natural gas liquids | 881,276 | — | 1,589,892 | 89 | |||||||||||
| Natural gas | — | — | — | (4 | ) | ||||||||||
| Total revenues | 11,066,911 | 8,529,817 | 19,604,782 | 16,123,757 | |||||||||||
| Operating costs | |||||||||||||||
| Production costs | 2,914,512 | 2,292,421 | 5,806,098 | 4,637,062 | |||||||||||
| Depreciation, depletion and amortization | 1,633,868 | 1,307,510 | 3,152,411 | 2,580,949 | |||||||||||
| Accretion of discount on asset retirement obligations | 23,023 | 13,106 | 44,602 | 26,330 | |||||||||||
| General and administrative expenses * | 1,666,256 | 1,241,399 | 3,235,960 | 2,476,442 | |||||||||||
| Total operating costs | 6,237,659 | 4,854,436 | 12,239,071 | 9,720,783 | |||||||||||
| Income from operations | 4,829,252 | 3,675,381 | 7,365,711 | 6,402,974 | |||||||||||
| Other | |||||||||||||||
| Gain on realized derivative instruments, net | — | — | — | 90 | |||||||||||
| Loss on unrealized derivative instruments, net | — | — | — | (14,132 | ) | ||||||||||
| Interest and other income | 15,841 | 14,061 | 30,691 | 26,806 | |||||||||||
| Interest expense | (20,456 | ) | (20,711 | ) | (40,911 | ) | (41,056 | ) | |||||||
| Income before income taxes | 4,824,637 | 3,668,731 | 7,355,491 | 6,374,682 | |||||||||||
| Income tax provision (benefit) | (5,052,211 | ) | 1,361,097 | (4,661,889 | ) | 2,250,273 | |||||||||
| Net income attributable to the Company | 9,876,848 | 2,307,634 | 12,017,380 | 4,124,409 | |||||||||||
| Dividends on preferred stock | — | — | — | 250,990 | |||||||||||
| Deemed dividend on redeemed preferred shares | — | — | — | 1,002,440 | |||||||||||
| Net income available to common stockholders | $ | 9,876,848 | $ | 2,307,634 | $ | 12,017,380 | $ | 2,870,979 | |||||||
| Earnings per common share | |||||||||||||||
| Basic | $ | 0.30 | $ | 0.07 | $ | 0.36 | $ | 0.09 | |||||||
| Diluted | $ | 0.30 | $ | 0.07 | $ | 0.36 | $ | 0.09 | |||||||
| Weighted average number of common shares | |||||||||||||||
| Basic | 33,109,448 | 33,047,166 | 33,099,546 | 33,002,088 | |||||||||||
| Diluted | 33,140,278 | 33,083,027 | 33,140,257 | 33,037,269 | |||||||||||
| Six Months Ended December 31, | |||||||
| 2017 | 2016 | ||||||
| Cash flows from operating activities | |||||||
| Net income attributable to the Company | $ | 12,017,380 | $ | 4,124,409 | |||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
| Depreciation, depletion and amortization | 3,180,545 | 2,609,356 | |||||
| Stock-based compensation | 971,810 | 586,872 | |||||
| Accretion of discount on asset retirement obligations | 44,602 | 26,330 | |||||
| Settlements of asset retirement obligations | — | (121,391 | ) | ||||
| Deferred income taxes (benefit) | (5,245,910 | ) | 1,709,519 | ||||
| Loss on derivative instruments, net | — | 14,042 | |||||
| Changes in operating assets and liabilities: | |||||||
| Receivables | (1,351,451 | ) | (462,981 | ) | |||
| Prepaid expenses and other current assets | (436,376 | ) | (367,039 | ) | |||
| Accounts payable and accrued expenses | (83,013 | ) | (1,955,546 | ) | |||
| Income taxes payable | — | (311,306 | ) | ||||
| Net cash provided by operating activities | 9,097,587 | 5,852,265 | |||||
| Cash flows from investing activities | |||||||
| Derivative settlement payments paid | — | (318,618 | ) | ||||
| Capital expenditures for oil and natural gas properties | (1,017,358 | ) | (7,978,130 | ) | |||
| Capital expenditures for other property and equipment | — | (30,447 | ) | ||||
| Net cash used in investing activities | (1,017,358 | ) | (8,327,195 | ) | |||
| Cash flows from financing activities | |||||||
| Cash dividends to preferred stockholders | — | (250,990 | ) | ||||
| Cash dividends to common stockholders | (4,969,335 | ) | (3,801,962 | ) | |||
| Common share repurchases, including shares surrendered for tax withholding | (395,550 | ) | (459,858 | ) | |||
| Redemption of preferred shares | — | (7,932,975 | ) | ||||
| Other | — | 32 | |||||
| Net cash used in financing activities | (5,364,885 | ) | (12,445,753 | ) | |||
| 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 | |||||
| Cash and cash equivalents, end of period | $ | 25,743,497 | $ | 19,156,377 | |||
| Supplemental disclosures of cash flow information: | Six Months Ended December 31, | ||||||
| 2017 | 2016 | ||||||
| Income taxes paid | $ | 1,136,754 | $ | 1,278,773 | |||
| Non-cash transactions: | |||||||
| Change in accounts payable used to acquire property and equipment | 424,365 | (1,516,932 | ) | ||||
| Oil and natural gas property costs incurred through recognition of asset retirement obligations | (779 | ) | — | ||||
(In thousands, except per share amounts)
| | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | ||||||||
| | March 31, | | March 31, | ||||||||
| | 2024 | | 2023 | | 2024 |
| 2023 | ||||
Revenues | | | | | | | | | | | | |
Crude oil | | $ | 14,538 | | $ | 11,799 | | $ | 38,913 | | $ | 40,062 |
Natural gas | | | 5,860 | | | 21,598 | | | 17,943 | | | 58,816 |
Natural gas liquids | | | 2,627 | | | 3,470 | | | 7,794 | | | 11,462 |
Total revenues | | | 23,025 | | | 36,867 | | | 64,650 | | | 110,340 |
Operating costs | | |
| | |
| | | | | |
|
Lease operating costs | | | 12,624 | | | 13,570 | | | 36,865 | | | 47,727 |
Depletion, depreciation, and accretion | | | 5,900 | | | 3,383 | | | 14,760 | | | 10,439 |
General and administrative expenses | | | 2,417 | | | 2,267 | | | 7,522 | | | 7,320 |
Total operating costs | | | 20,941 | | | 19,220 | | | 59,147 | | | 65,486 |
Income (loss) from operations | | | 2,084 | | | 17,647 | | | 5,503 | | | 44,854 |
Other income (expense) | | |
| | |
| | | | | |
|
Net gain (loss) on derivative contracts | | | (1,183) | | | 270 | | | (1,183) | | | 513 |
Interest and other income | | | 63 | | | 13 | | | 283 | | | 26 |
Interest expense | | | (518) | | | (32) | | | (584) | | | (404) |
Income (loss) before income taxes | | | 446 | | | 17,898 | | | 4,019 | | | 44,989 |
Income tax (expense) benefit | | | (157) | | | (3,941) | | | (1,174) | | | (9,938) |
Net income (loss) | | $ | 289 | | $ | 13,957 | | $ | 2,845 | | $ | 35,051 |
Net income (loss) per common share: | | |
| | |
| | |
| | |
|
Basic | | $ | 0.01 | | $ | 0.42 | | $ | 0.09 | | $ | 1.04 |
Diluted | | $ | 0.01 | | $ | 0.41 | | $ | 0.08 | | $ | 1.04 |
Weighted average number of common shares outstanding: | | |
| | |
| | |
| | |
|
Basic | | | 32,702 | | | 33,013 | | | 32,692 | | | 33,108 |
Diluted | | | 32,854 | | | 33,156 | | | 32,920 | | | 33,291 |
See accompanying notes to unaudited condensed consolidated condensed financial statements.
5
| Common Stock | |||||||||||||||||||||||
| Additional Paid-in Capital | Retained Earnings | Treasury Stock | Total Stockholders' Equity | ||||||||||||||||||||
| Shares | Par Value | ||||||||||||||||||||||
| Balance at June 30, 2017 | 33,087,308 | $ | 33,087 | $ | 40,961,957 | $ | 27,474,811 | $ | — | $ | 68,469,855 | ||||||||||||
| Issuance of restricted common stock | 158,785 | 158 | (158 | ) | — | — | — | ||||||||||||||||
| Forfeitures of restricted stock | (19,561 | ) | (20 | ) | 20 | — | — | — | |||||||||||||||
| Common share repurchases, including shares surrendered for tax withholding | (55,018 | ) | — | — | — | (395,550 | ) | (395,550 | ) | ||||||||||||||
| Retirements of treasury stock | — | (54 | ) | (395,496 | ) | — | 395,550 | — | |||||||||||||||
| Stock-based compensation | — | — | 971,810 | — | — | 971,810 | |||||||||||||||||
| 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 | ||||||||||||
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| | | | | | |
| | Nine Months Ended March 31, | ||||
|
| 2024 |
| 2023 | ||
Cash flows from operating activities: | | |
| | |
|
Net income (loss) | | $ | 2,845 | | $ | 35,051 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | |
| | | |
Depletion, depreciation, and accretion | | | 14,760 | | | 10,439 |
Stock-based compensation | | | 1,585 | | | 1,155 |
Settlement of asset retirement obligations | | | (19) | | | (119) |
Deferred income taxes | | | 124 | | | (100) |
Unrealized (gain) loss on derivative contracts | | | 1,063 | | | (1,994) |
Accrued settlements on derivative contracts | | | 94 | | | (1,130) |
Other | | | — | | | (3) |
Changes in operating assets and liabilities: | | |
| | | |
Receivables from crude oil, natural gas, and natural gas liquids revenues | | | (4,734) | | | 16,483 |
Prepaid expenses and other current assets | | | (1,425) | | | (980) |
Accounts payable and accrued liabilities | | | 814 | | | (8,146) |
State and federal income taxes payable | | | (365) | | | 1,063 |
Net cash provided by operating activities | | | 14,742 | | | 51,719 |
Cash flows from investing activities: | | | | | | |
Acquisition of oil and natural gas properties | | | (43,788) | | | (31) |
Capital expenditures for oil and natural gas properties | | | (8,353) | | | (4,234) |
Net cash used in investing activities | | | (52,141) | | | (4,265) |
Cash flows from financing activities: | | |
| | |
|
Common stock dividends paid | | | (12,037) | | | (12,114) |
Common stock repurchases, including stock surrendered for tax withholding | | | (1,031) | | | (3,983) |
Borrowings under senior secured credit facility | | | 42,500 | | | — |
Repayments of senior secured credit facility | | | — | | | (21,250) |
Net cash (used in) provided by financing activities | | | 29,432 | | | (37,347) |
Net increase (decrease) in cash and cash equivalents | | | (7,967) | | | 10,107 |
Cash and cash equivalents, beginning of period | | | 11,034 | | | 8,280 |
Cash and cash equivalents, end of period | | $ | 3,067 | | $ | 18,387 |
| | | | | | |
Supplemental disclosures of cash flow information: | | | | | | |
Non-cash investing and financing transactions: | | | | | | |
Increase (decrease) in accrued capital expenditures for oil and natural gas properties | | $ | 2,193 | | $ | (141) |
Oil and natural gas property costs attributable to the recognition of asset retirement obligations | | | 90 | | | — |
See accompanying notes to unaudited condensed consolidated condensed financial statements.
6
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)
(In thousands)
| | | | | | | | | | | | | | | | | |
| | | | | | | Additional | | |
| | |
| | Total | ||
| | Common Stock | | Paid-in | | Retained | | Treasury | | Stockholders' | |||||||
|
| Shares |
| Par Value |
| Capital |
| Earnings |
| Stock |
| Equity | |||||
For the Three Months Ended March 31, 2024 | | | | | | | | | | | | | | | | | |
Balances at December 31, 2023 | | 33,507 | | $ | 34 | | $ | 40,920 | | $ | 46,485 | | $ | — | | $ | 87,439 |
Issuance of restricted common stock | | 5 | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (818) | | | (818) |
Retirements of treasury stock | | (152) | | | (1) | | | (817) | | | — | | | 818 | | | — |
Stock-based compensation | | — | | | — | | | 549 | | | — | | | — | | | 549 |
Net income (loss) | | — | | | — | | | — | | | 289 | | | — | | | 289 |
Common stock dividends paid | | — | | | — | | | — | | | (4,003) | | | — | | | (4,003) |
Balances at March 31, 2024 | | 33,360 | | $ | 33 | | $ | 40,652 | | $ | 42,771 | | $ | — | | $ | 83,456 |
| | | | | | | | | | | | | | | | | |
For the Nine Months Ended March 31, 2024 | | | | | | | | | | | | | | | | | |
Balances at June 30, 2023 | | 33,248 | | $ | 33 | | $ | 40,098 | | $ | 51,963 | | $ | — | | $ | 92,094 |
Issuance of restricted common stock | | 293 | | | 1 | | | (1) | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (1,031) | | | (1,031) |
Retirements of treasury stock | | (181) | | | (1) | | | (1,030) | | | — | | | 1,031 | | | — |
Stock-based compensation | | — | | | — | | | 1,585 | | | — | | | — | | | 1,585 |
Net income (loss) | | — | | | — | | | — | | | 2,845 | | | — | | | 2,845 |
Common stock dividends paid | | — | | | — | | | — | | | (12,037) | | | — | | | (12,037) |
Balances at March 31, 2024 | | 33,360 | | $ | 33 | | $ | 40,652 | | $ | 42,771 | | $ | — | | $ | 83,456 |
| | | | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2023 | | | | | | | | | | | | | | | | | |
Balances at December 31, 2022 | | 33,808 | | $ | 34 | | $ | 43,243 | | $ | 45,861 | | $ | — | | $ | 89,138 |
Issuance of restricted common stock | | 101 | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (3,896) | | | (3,896) |
Retirements of treasury stock | | (638) | | | (1) | | | (3,895) | | | — | | | 3,896 | | | — |
Stock-based compensation | | — | | | — | | | 453 | | | — | | | — | | | 453 |
Net income (loss) | | — | | | — | | | — | | | 13,957 | | | — | | | 13,957 |
Common stock dividends paid | | — | | | — | | | — | | | (4,029) | | | — | | | (4,029) |
Balances at March 31, 2023 | | 33,271 | | $ | 33 | | $ | 39,801 | | $ | 55,789 | | $ | — | | $ | 95,623 |
| | | | | | | | | | | | | | | | | |
For the Nine Months Ended March 31, 2023 | | | | | | | | | | | | | | | | | |
Balances at June 30, 2022 | | 33,471 | | $ | 33 | | $ | 42,629 | | $ | 32,852 | | $ | — | | $ | 75,514 |
Issuance of restricted common stock | | 476 | | | 1 | | | (1) | | | — | | | — | | | — |
Forfeitures of restricted stock | | (26) | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | (3,983) | | | (3,983) |
Retirements of treasury stock | | (650) | | | (1) | | | (3,982) | | | — | | | 3,983 | | | — |
Stock-based compensation | | — | | | — | | | 1,155 | | | — | | | — | | | 1,155 |
Net income (loss) | | — | | | — | | | — | | | 35,051 | | | — | | | 35,051 |
Common stock dividends paid | | — | | | — | | | — | | | (12,114) | | | — | | | (12,114) |
Balances at March 31, 2023 | | 33,271 | | $ | 33 | | $ | 39,801 | | $ | 55,789 | | $ | — | | $ | 95,623 |
See accompanying notes to unaudited condensed consolidated financial statements.
7
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Financial Statement Presentation
Nature of Operations. Evolution Petroleum Corporation And Subsidiaries
The Company’s oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the StateAnadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of Nevada. We are engaged primarilyNew Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the development and production ofDelhi Field in Northeast Louisiana, a CO2 enhanced oil and gas reserves.
Interim Financial Statements.
The accompanying unaudited condensed consolidatedPrinciples of Consolidation and Reporting.
Risk and Uncertainties. The Company’s oil and natural gas interests are operated by third-party operators and involve other third-party working interest owners. As a result, the Company has limited ability to influence the operation or future development of such properties. However, the Company is proactive with its third-party operators to review capital projects and related spending and present alternative plans as appropriate.
Oil and Natural Gas Properties. The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-
8
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined.
Use of Estimates. The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with GAAP requires usthe Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities, if any, at the datesdate of the consolidated financial statements and the reported amounts of revenues and expenses during the respective 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 contract assets and liabilities, (e) income taxes and the valuation of deferred income tax assets, and (f) commitments and contingencies. We analyze ourcontingencies, and (g) accruals of crude oil, natural gas, and NGL revenues and expenses. The Company analyzes estimates and judgments based on historical experience and various other assumptions and information that we believeare believed to be reasonable. While we believe that ourEstimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as additional information is obtained, as new events occur, and as the Company’s environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements are appropriate, actual results could differ from those estimates.
Recently Issued Accounting Pronouncements.
In August 2015,December 2023, the Financial Accounting Standards Board ("FASB")FASB issued Accounting Standards Update 2015-14, which defersASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 enhances the effective datetransparency of income tax disclosures by expanding the income tax rate reconciliation disclosure and income taxes paid information. ASU 2014-09
In JanuaryJune 2016, the FASB issued ASU 2016-01,
Other accounting pronouncements that have recently been issued by the Company and the adoption isFASB or other standards-setting bodies are not expected to have a significantmaterial impact on the Company’s consolidated financial position, or results of operations.
Note 2. Revenue Recognition
The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the SCOOP and STACK plays in central Oklahoma, the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico, the Jonah Field in Sublette County, Wyoming, the Williston Basin in North Dakota, the Barnett Shale located in North Texas, the Hamilton Dome Field in Wyoming, and the Delhi Field in Northeast Louisiana. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provides de minimis revenue. The following table
9
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
disaggregates the Company’s revenues by major product for the three and nine months ended March 31, 2024 and 2023 (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | ||||||||
| | March 31, | | March 31, | ||||||||
|
| 2024 | | 2023 | | 2024 |
| 2023 | ||||
Revenues | | | | | | | | | | | | |
Crude oil | | $ | 14,538 | | $ | 11,799 | | $ | 38,913 | | $ | 40,062 |
Natural gas | | | 5,860 | | | 21,598 | | | 17,943 | | | 58,816 |
Natural gas liquids | | | 2,627 | | | 3,470 | | | 7,794 | | | 11,462 |
Total revenues | | $ | 23,025 | | $ | 36,867 | | $ | 64,650 | | $ | 110,340 |
In the Jonah Field, the Company has elected to Unaudited Consolidated Condensed Financial Statements
The Company does not take production in-kind at any of its other properties and does not negotiate contracts with customers for such production. The Company recognizes crude oil, natural gas, and NGL production revenue at the FASB issued ASU 2016-02 ,
Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear orCompany does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017,believe that significant judgments are required with respect to the determination of the transaction price, including interim periods within those fiscal yearsamounts 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 early adoption permitted, provided that it is adopted in its entirety in the same period. Currently,predictable differentials. Accordingly, the Company does not expectconsider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the impactproduction of adopting ASU 2016-15hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control of produced hydrocarbons transferring to a customer at a specified delivery point. Consideration is allocated to completed 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 by field operators one to two months before the Company receives payment and documentation from the operator, which is typical in the oil and natural gas 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 the sale of the product. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, information from field operators, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors. Because the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude oil, natural gas, and natural gas liquids revenues” on the unaudited condensed consolidated balance sheets. Differences between estimates and actual amounts received for product sales are recorded in the month that payments received from purchasers are remitted to the Company by field operators.
10
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Acquisitions
SCOOP/STACK Acquisitions
On February 12, 2024, the Company closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows received on the properties subsequent to closing. The Company expects to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement expected to occur during the fourth quarter of fiscal 2024. The Company accounted for these transactions as asset acquisitions and allocated all of the combined purchase price (including $0.2 million of transaction costs) to proved oil and natural gas properties. In addition, the Company recognized $0.1 million in non-cash asset retirement obligations, the estimated net present value of future net retirement costs. The transactions were funded with cash on hand and $42.5 million in borrowings under the Company’s Senior Secured Credit Facility.
The acquired assets consist of an average net working interest of approximately 3%, in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.
Chaveroo Oilfield Participation Agreement
On September 12, 2023, the Company entered into a material effect on its consolidated statementsParticipation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo oilfield, located in Chaves and Roosevelt Counties, New Mexico. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells.
Upon signing the Participation Agreement, the Company paid total cash flows.
Note 4. Property and Equipment
Property and equipment as of March 31, 2024 and June 30, 2017, our receivables2023 consisted of the following:following (in thousands):
| | | | | | |
|
| March 31, 2024 |
| June 30, 2023 | ||
Oil and natural gas properties | | |
| | |
|
Property costs subject to amortization | | $ | 247,106 | | $ | 197,049 |
Less: Accumulated depletion, depreciation, and impairment | | | (104,949) | | | (91,268) |
Oil and natural gas properties, net | | $ | 142,157 | | $ | 105,781 |
The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated
11
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| 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 | |||
depletion, exceed the discounted future net revenues of proved oil and Other Current Assets
Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration 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 | |||
Depletion of oil and natural gas properties was $13.7 million and $9.6 million for the nine months ended March 31, 20172024 and June 30, 2017, our2023, respectively. During the nine months ended March 31, 2024 and 2023, the Company incurred development capital expenditures of $9.4 million and $4.4 million, respectively.
At March 31, 2024, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended March 31, 2024 of the West Texas Intermediate (“WTI”) crude oil spot price of $77.64 per barrel and Henry Hub natural gas spot price of $2.44 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $29.88, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at March 31, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties and, other property and equipment consistedas a result, no write-down was applicable.
At March 31, 2023, the ceiling test value of the following:
| December 31, 2017 | June 30, 2017 | ||||||
| Oil and natural gas properties | |||||||
| Property costs subject to amortization | $ | 86,403,877 | $ | 84,962,933 | |||
| Less: Accumulated depreciation, depletion, and amortization | (26,310,070 | ) | (23,172,865 | ) | |||
| Unproved properties not subject to amortization | — | — | |||||
| Oil and natural gas properties, net | $ | 60,093,807 | $ | 61,790,068 | |||
| Other property and equipment | |||||||
| Furniture, fixtures, office equipment and other, at cost | $ | 135,377 | $ | 135,377 | |||
| Less: Accumulated depreciation | (103,112 | ) | (94,688 | ) | |||
| Other property and equipment, net | $ | 32,265 | $ | 40,689 | |||
Note 5. Senior Secured Credit Facility
On April 11, 2016, the Company incurred capital expendituresentered into a three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $1.4$50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate ("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively convert SOFR to a LIBOR equivalent and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
12
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.
The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of March 31, 2024, the Company had $42.5 million borrowings outstanding under its Senior Secured Credit Facility, resulting in $7.5 million of available borrowing capacity. For the nine months ended March 31, 2024 and 2023, the weighted average interest on borrowings under the Senior Secured Credit Facility was 8.13% and 5.25%, respectively. As of March 31, 2024, the Company is in compliance with the financial covenants under the Senior Secured Credit Facility.
On February 12, 2024, the Company entered into an amendment to the Senior Secured Credit Facility. This amendment required that the Company enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. The Company has the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.
On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.
On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and $6.5 million, respectively,added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Delhi field.subsequent amendments, as discussed above.
Note 6. Income Taxes
The Company files a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.
There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the periods presented in the unaudited condensed consolidated financial statements. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax
13
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2020 through June 30, 2023 for federal tax purposes and for the fiscal years ended June 30, 2019 through June 30, 2023 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.
For nine months ended March 31, 2024, the Company recognized income tax expense of $1.2 million and had an effective tax rate of 29.2% compared to income tax expense of $9.9 million and an effective tax rate of 22.1% for the nine months ended March 31, 2023.
The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana, Oklahoma and North Dakota, percentage depletion in excess of basis, and other permanent differences. For both periods, the respective statutory federal tax rate was 21%.
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
Note 7. Derivatives
The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 5,
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of DecemberMarch 31, 20172024, the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.
When the Company utilizes commodity derivative contracts, it expects to enter into deferred premium puts, costless put/call collars and/or fixed-price swaps to hedge a portion of its anticipated future production. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.
All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”) and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of March 31, 2024 (the “mark-to-market valuation”).
14
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2024 and June 30, 2017, other assets consisted2023 (in thousands):
| | | | | | | | | | | | | | | | |
Derivatives not designated | | | | | | | | | ||||||||
as hedging contracts | | Balance sheet | | Derivative Contract Assets | | Balance sheet | | Derivative Contract Liabilities | ||||||||
under ASC 815 |
| location |
| March 31, 2024 |
| June 30, 2023 |
| location |
| March 31, 2024 |
| June 30, 2023 | ||||
Commodity contracts | | Current assets - derivative contract assets | | $ | 347 | | $ | — | | Current liabilities - derivative contract liabilities | | $ | 1,410 | | $ | — |
Commodity contracts | | Other assets - derivative contract assets | | | — | | | — | | Long term liabilities - derivative contract liabilities | | | — | | | — |
Total derivatives not designated as hedging contracts under ASC 815 | | | | $ | 347 | | $ | — | | | | $ | 1,410 | | $ | — |
The following table summarizes the location and amounts of the following:
| December 31, 2017 | June 30, 2017 | ||||||
| Royalty rights | $ | 108,512 | $ | 108,512 | |||
| Less: Accumulated amortization of royalty rights | (27,128 | ) | (20,346 | ) | |||
| Investment in Well Lift Inc., at cost | 108,750 | 108,750 | |||||
| Deferred loan costs | 168,972 | 168,972 | |||||
| Less: Accumulated amortization of deferred loan costs | (98,638 | ) | (70,504 | ) | |||
| Other assets, net | $ | 260,468 | $ | 295,384 | |||
| | | | | | | | | | | | | | |
Derivatives not designated | | Location of gain (loss) | | Three Months Ended | | Nine Months Ended | ||||||||
as hedging contracts | | recognized in income on | | March 31, | | March 31, | ||||||||
under ASC 815 |
| derivative contracts |
| 2024 | | 2023 | | 2024 |
| 2023 | ||||
Commodity contracts: | | | | | | | | | | | | | | |
Realized gain (loss) on derivative contracts | | Other income and expenses - net gain (loss) on derivative contracts | | $ | (120) | | $ | 465 | | $ | (120) | | $ | (1,481) |
Unrealized gain (loss) on derivative contracts | | Other income and expenses - net gain (loss) on derivative contracts | | | (1,063) | | | (195) | | | (1,063) | | | 1,994 |
Total net gain (loss) on derivative contracts | | | | $ | (1,183) | | $ | 270 | | $ | (1,183) | | $ | 513 |
As of WLIMarch 31, 2024, the Company had the following open crude oil and account for our investment undernatural gas derivative contracts:
| | | | | | | | | | | | | | | |
| | | | | | | | Weighted Average | | Weighted Average | | Weighted Average | |||
| | | | | | Volumes in | | Swap Price per | | Floor Price per | | Ceiling Price per | |||
Period |
| Instrument |
| Commodity |
| MMBTU/BBL | | MMBTU/BBL |
| MMBTU/BBL |
| MMBTU/BBL | |||
April 2024 - June 2024 | | Fixed-Price Swap | | Crude Oil | | 24,250 | | $ | 73.41 | | | | | | |
April 2024 - June 2024 | | Fixed-Price Swap | | Crude Oil | | 14,467 | | | 73.30 | | | | | | |
April 2024 - June 2024 | | Put | | Crude Oil | | 38,717 | | | | | $ | 75.00 | | | |
July 2024 - December 2024 | | Fixed-Price Swap | | Crude Oil | | 73,558 | | | 74.20 | | | | | | |
July 2024 - December 2024 | | Collar | | Crude Oil | | 73,558 | | | | | | 70.00 | | $ | 77.40 |
January 2025 - March 2025 | | Collar | | Crude Oil | | 42,566 | | | | | | 68.00 | | | 73.77 |
January 2025 - February 2025 | | Fixed-Price Swap | | Natural Gas | | 312,286 | | | 3.56 | | | | | | |
15
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Subsequent to March 31, 2024, the cost method. Any dividends paid are recorded as incomeCompany entered into the following open crude oil and any returnnatural gas derivative contracts:
| | | | | | | | | | | | | | | |
| | | | | | | | Weighted Average | | Weighted Average | | Weighted Average | |||
| | | | | | Volumes in | | Swap Price per | | Floor Price per | | Ceiling Price per | |||
Period |
| Instrument |
| Commodity |
| MMBTU/BBL | | MMBTU/BBL |
| MMBTU/BBL |
| MMBTU/BBL | |||
April 2025 - June 2025 | | Collar | | Crude Oil | | 41,601 | | | | | $ | 65.00 | | $ | 84.00 |
March 2025 - December 2026 | | Fixed-Price Swap | | Natural Gas | | 3,170,705 | | $ | 3.60 | | | | | | |
The Company presents the fair value of capital reduces our cost basisits derivative contracts at the gross amounts in the investment. Our investment in WLI is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that might have a significant adverse effectunaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the investment. ThereCompany’s derivative contracts as of March 31, 2024 and June 30, 2023 (in thousands):
| | | | | | | | | | | | |
| | Derivative Contracts Assets | | Derivative Contracts Liabilities | ||||||||
Offsetting of Derivative Assets and Liabilities |
| March 31, 2024 |
| June 30, 2023 |
| March 31, 2024 |
| June 30, 2023 | ||||
Gross amounts presented in the Consolidated Balance Sheet | | $ | 347 | | $ | — | | $ | 1,410 | | $ | — |
Amounts not offset in the Consolidated Balance Sheet | | | (347) | | | — | | | (347) | | | — |
Net amount | | $ | — | | $ | — | | $ | 1,063 | | $ | — |
The Company enters into an International Swap Dealers Association Master Agreements (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
Note 8. Fair Value Measurement
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
The three levels are defined as follows:
Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3—Unobservable inputs for which there are little or no published market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair Value of Derivative Instruments. The Company’s determination of fair value for this private investment, so itincorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is not practicabledefined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market
16
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
corroborated (Level 2), or generally unobservable (Level 3). The Company classifies fair value balances based on observability of those inputs.
| | | | | | | | | | | | |
| | March 31, 2024 | ||||||||||
|
| Level 1 |
| Level 2 |
| Level 3 |
| Total | ||||
Assets | | | | | | | | | | | | |
Derivative contract assets | | $ | — | | $ | 347 | | $ | — | | $ | 347 |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Derivative contract liabilities | | $ | — | | $ | 1,410 | | $ | — | | $ | 1,410 |
Derivative contracts listed above as Level 2 include fixed-price swaps and costless put/call collars that are carried at fair value. The Company records the net change in fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value itthe assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 7, “Derivatives,” for additional discussion of derivatives.
The Company’s derivative contracts are with large utilities with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not expect such nonperformance.
As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report.
Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market rates.
The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a periodicnon-recurring basis.
| December 31, 2017 | June 30, 2017 | ||||||
| Accrued incentive and other compensation | $ | 292,382 | $ | 413,113 | |||
| Accrued severance payments | 46,719 | — | |||||
| Asset retirement obligations due within one year | 35,539 | 35,115 | |||||
| Accrued royalties, including suspended accounts | 11,524 | 17,708 | |||||
| Accrued franchise taxes | 82,800 | 150,062 | |||||
| Accrued ad valorem taxes | 191,503 | 108,641 | |||||
| Accrued liabilities and other | $ | 660,467 | $ | 724,639 | |||
17
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Asset Retirement Obligations
The Company’s ARO represents the estimated present value of the amount we expectexpected to incurbe incurred to plug, abandon, and remediate our producingits oil and natural gas properties at the end of their productive lives in accordance with applicable laws. laws and regulations. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties, subject to amortization, net” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the unaudited condensed consolidated statements of operations.
The following is a reconciliation of the beginning and ending asset retirement obligationsactivity related to the Company’s ARO liability (inclusive of the current portion) for the six monthsperiod ended DecemberMarch 31, 2017 and for the year ended June 30, 2017:
| | | |
|
| March 31, 2024 | |
Asset retirement obligations — beginning of period | | $ | 17,067 |
Liabilities acquired(1) | | | 90 |
Accretion of discount | | | 1,080 |
Asset retirement obligations — end of period | | | 18,237 |
Less: current asset retirement obligations | | | (158) |
Long-term portion of asset retirement obligations | | $ | 18,079 |
| 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 | |||
| (1) | See Note 3, “Acquisitions,” for additional information on the Company’s acquisition activities. |
Note 8 —10. Commitments and Contingencies
The Company is subject to various claims and contingencies in the normal course of business. In addition, from time to time, the Company receives communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which the Company operates. The Company discloses such matters if it believes there is a reasonable possibility that a future event or events will confirm a material loss through impairment of an asset or the incurrence of a material liability. The Company accrues a material loss if it believes it probable that a future event or events will confirm a loss and the loss is reasonably subject to estimation. Furthermore, the Company will disclose any matter that is unasserted if it considers it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable and material in amount. The Company expenses legal defense costs as they are incurred.
Note 11. Stockholders’ Equity
Common Stock
As of DecemberMarch 31, 2017, we2024, the Company had 33,171,514 sh
The Company began paying quarterly cash dividends on common stock in December 2013. WeAs of March 31, 2024, the Company has cumulatively paid over $114.4 million in cash dividends. The Company paid dividends of $4,969,335$12.0 million and $3,801,962$12.1 million to ourits common shareholdersstockholders during the sixnine months ended DecemberMarch 31, 20172024 and 2016,2023, respectively. These dividend payments consisted
18
Table of two quarterlyContents
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table reflects the dividends of $0.075paid per share each duringwithin 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.
| | | | | | |
| | Fiscal Year | ||||
|
| 2024 |
| 2023 | ||
Third quarter ended March 31, | | $ | 0.120 | | $ | 0.120 |
Second quarter ended December 31, | | | 0.120 | | | 0.120 |
First quarter ended September 30, | | | 0.120 | | | 0.120 |
On September 8, 2022, the Board of Directors approved a share repurchase program, coveringunder which the Company is authorized to repurchase up to $5$25.0 million of the Company'sits common stock. Between June 2015 and December 2015, the Company spent $1,609,008 to repurchase 265,762 common shares at an average price of $6.05 per share. There have been no shares repurchasedstock in the open market sincethrough December 2015. Under31, 2024. The Company intends to fund repurchases from working capital and cash provided by operating activities. The Board of Directors along with the program's terms,management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares aremay be repurchased only on thefrom time to time in open market andtransactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the requirementsnumber and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the Securitiesintrinsic value of the Company’s shares, the market price of the Company’s common stock, the Company’s capital needs 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, andgeneral market and business conditions. There is no fixed termination dateeconomic conditions, and applicable legal requirements. The value of shares authorized for this repurchase program,by the Company’s Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and itthe program may be suspended, modified, or discontinued at any time.
In December 2022, the Company entered into a Rule 10b5-1 plan that authorized a broker to Unaudited Consolidated Condensed Financial Statements
In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and 2016,price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $0.8 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.
During the nine months ended March 31, 2024 and 2023, the Company acquired treasury stock from holdersupon the ordinary course of newly vestedscheduled vestings of employee stock-based awards to fund the recipients' payroll tax withholding obligations. TheThese treasury shares were subsequently canceled.cancelled. Such shares were valued at fair market value on the date of vesting, as reflected investing.
19
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | |
| | Nine Months Ended | ||||
| | March 31, | ||||
|
| 2024 | | 2023 | ||
Number of treasury shares acquired(1) | | | 181 | | | 650 |
Average cost per share(1) | | $ | 5.70 | | $ | 6.13 |
Total cost of treasury shares acquired | | $ | 1,031 | | $ | 3,983 |
| Six Months Ended December 31, | |||||||
| 2017 | 2016 | ||||||
| Number of treasury shares acquired | 55,018 | 73,455 | |||||
| Average cost per share | $ | 7.19 | $ | 6.26 | |||
| Total cost of treasury shares acquired | $ | 395,550 | $ | 459,858 | |||
| (1) | For the nine months ended March 31, 2024, includes 140,672 shares repurchased under the Company’s share repurchase program for a weighted average price of $5.33 per share. For the nine months ended March 31, 2023, includes 633,789 shares repurchased under the Company’s share repurchase program for a weighted average price of $6.07 per share. |
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2017,2023, all preferred and common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on ourits current projections for the fiscal year endingended June 30, 2018, we expect2024, the Company expects all common stock dividends for such period to be treated as qualified dividend income.income to the recipients. Such projections are based on ourthe Company’s reasonable expectations as of DecemberMarch 31, 20172024 and are subject to change based on ourthe Company’s final tax calculations at the end of the fiscal year.
Stock-Based Incentive Plan
The Evolution Petroleum Corporation 2016 Equity Incentive Plan (the(as amended, the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,0003.6 million 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, ourthe Company’s common stock, including its appreciation in value. As of DecemberMarch 31, 2017, 987,8452024 and June 30, 2023, approximately 0.9 million shares and 1.3 million shares, respectively, remained available for grant under the 2016 Plan.
The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future grants undercompensation expense. During the 2004 Plan. All outstanding awards granted underthree and nine months ended March 31, 2024, the 2004 Plan continueCompany recognized $0.5 million and $1.6 million, respectively, related to be subjectstock-based compensation. During the three and nine months ended March 31, 2023, the Company recognized $0.5 million and $1.2 million, respectively, related to stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the terms and conditions as set forth in the agreements evidencing such awards and the termsunaudited condensed consolidated statements of the 2004 Plan. Under these agreements, we have outstanding grants ofoperations.
Time-Vested Restricted Stock Awards
Time-vested restricted common stock awards ("Restricted Stock")contain service-based vesting conditions and contingent restricted common stock awards ("Contingent Restricted Stock") to employees and directors of the Company.
20
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Performance-Based Restricted Stock grants which vestAwards and Performance-Based Contingent Stock Units
Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting conditions based on servicethe price of the Company’s common stock, the intrinsic value indexed solely to its common stock or the intrinsic value indexed to its common stock compared to the performance of the common stock of its peers. The common shares underlying the Company’s performance-based restricted stock awards are valued at the fair market valueissued on the date of grant and amortized overparticipate in dividends paid by the service period. DuringCompany and expire after a maximum of four years from the six months ended December 31, 2017, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employeesdate of grant if unvested. Performance-based contingent share units do not participate in dividends and 66,944 awards to directors, substantially all of which have a one-year vesting period. We did not grant any performance-basedshares are only issued in part or market based awards, nor any Contingent Restricted Stock awards, during this period.
Vesting of grants with performance-based vesting conditions is dependent on the grant date fair value when it is deemed probable, for accounting purposes, thatfuture price of the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four-year term. As of December 31, 2017, certain contingent 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.
During the nine months ended March 31, 2024, the Company granted a total of companies0.4 million equity awards that included 0.2 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and 0.1 million performance-based contingent stock units.
During the nine months ended March 31, 2023, the Company granted a total of 0.5 million equity awards that included 0.4 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and less than 0.05 million of performance-based contingent stock units.
For performance-based awards granted during the nine months ended March 31, 2024 and 2023, the assumptions used in our industry. The fair values and expected vesting periods of these awards are determined using athe Monte Carlo simulation based on the historical volatilityvaluations were as follows:
| | | | | | |
| | Nine Months Ended | ||||
| | March 31, | ||||
|
| 2024 |
| 2023 | ||
Weighted average fair value of performance-based awards granted | | $ | 3.58 | | $ | 6.52 |
Risk-free interest rate | | | 4.87% | | | 3.91% to 4.51% |
Expected term in years | | | 2.77 | | | 2.36 to 2.78 |
Expected volatility | | | 55.0% | | | 56.5% to 70.9% |
Dividend yield | | | 7.4% | | | 6.1% to 7.8% |
21
Table of the Company's total return compared to the historical volatilitiesContents
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unvested restricted stock awards as 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.
| 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 | |||
| | | | | |
| | | | Weighted | |
| | Number of | | Average | |
| | Restricted | | Grant-Date | |
Award Type |
| Shares |
| Fair Value | |
Time-vested awards | | 407,103 | | $ | 6.59 |
Performance-based awards | | 278,688 | | | 5.46 |
Unvested at March 31, 2024 | | 685,791 | | $ | 6.13 |
The following table sets forth the Restricted Stockrestricted stock award transactions for the sixnine months ended DecemberMarch 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 | ||||||
| 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 | |||
| | | | | | | | | | |
| | | | | | | | | | Weighted |
| | | | Weighted | | Unamortized | | Average | ||
| | Number of | | Average | | Compensation | | Remaining | ||
| | Restricted | | Grant-Date | | Expense | | Amortization | ||
|
| Shares |
| Fair Value |
| (In thousands) |
| Period (Years) | ||
Unvested at June 30, 2023 | | 595,414 | | | 6.48 | | $ | 2,827 | | 2.4 |
Time-vested shares granted | | 157,192 | | | 6.22 | | | | | |
Performance-based shares granted | | 136,315 | | | 4.80 | | | | | |
Vested | | (203,130) | | | 6.33 | | | | | |
Unvested at March 31, 2024 | | 685,791 | | $ | 6.13 | | $ | 2,995 | | 1.9 |
The following table sets forth Contingent Restricted Stockcontingent restricted stock unit transactions for the sixnine months ended DecemberMarch 31, 2017:2024:
| | | | | | | | | | |
| | | | | | | | | Weighted | |
| | | | | | | Unamortized | | Average | |
| | Number of | | Weighted Average | | Compensation | | Remaining | ||
| | Restricted | | Grant-Date | | Expense | | Amortization | ||
|
| Stock Units |
| Fair Value |
| (In thousands) |
| Period (Years) | ||
Unvested at June 30, 2023 | | 96,398 | | $ | 3.49 | | $ | 195 | | 1.9 |
Performance-based awards granted | | 102,239 | | | 1.95 | | | | | |
Unvested at March 31, 2024 | | 198,637 | | $ | 2.70 | | $ | 275 | | 1.8 |
22
| 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) | |||||||||
| Unvested at July 1, 2017 | 113,270 | $ | 4.64 | |||||||||
| Vested | (46,630 | ) | 3.34 | |||||||||
| Forfeited | (4,772 | ) | 5.30 | |||||||||
| Unvested contingent shares at December 31, 2017 | 61,868 | $ | 5.57 | $ | 84,005 | 1.03 | ||||||
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the computation of basic and diluted incomeearnings (loss) per share:
| Three Months Ended December 31, | Six Months Ended December 31, | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Numerator | |||||||||||||||
| Net income available to common shareholders | $ | 9,876,848 | $ | 2,307,634 | $ | 12,017,380 | $ | 2,870,979 | |||||||
| Denominator | |||||||||||||||
| Weighted average number of common shares — Basic | 33,109,448 | 33,047,166 | 33,099,546 | 33,002,088 | |||||||||||
| Effect of dilutive securities: | |||||||||||||||
| Contingent restricted stock grants | 30,830 | 9,836 | 40,711 | 10,909 | |||||||||||
| 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 | |||||||||||
| Net income per common share — Basic | $ | 0.30 | $ | 0.07 | $ | 0.36 | $ | 0.09 | |||||||
| Net income per common share — Diluted | $ | 0.30 | $ | 0.07 | $ | 0.36 | $ | 0.09 | |||||||
| | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | ||||||||
| | March 31, | | March 31, | ||||||||
|
| 2024 | | 2023 | | 2024 |
| 2023 | ||||
Numerator | | |
| | |
| | |
| | |
|
Net income (loss) | | $ | 289 | | $ | 13,957 | | $ | 2,845 | | $ | 35,051 |
Undistributed earnings allocated to unvested restricted stock | | | (6) | | | (253) | | | (58) | | | (515) |
Net income (loss) for earnings per share calculation | | $ | 283 | | $ | 13,704 | | $ | 2,787 | | $ | 34,536 |
| | |
| | |
| | |
| | |
|
Denominator | | | | | | | | | | | | |
Weighted average number of common shares outstanding — Basic | | | 32,702 | | | 33,013 | | | 32,692 | | | 33,108 |
Effect of dilutive securities: | | | | | | | | | | | | |
Unvested restricted stock awards | | | 124 | | | 143 | | | 192 | | | 178 |
Unvested contingent restricted stock units | | | 28 | | | — | | | 36 | | | 5 |
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share | | | 32,854 | | | 33,156 | | | 32,920 | | | 33,291 |
| | | | | | | | | | | | |
Net income (loss) per common share — Basic | | $ | 0.01 | | $ | 0.42 | | $ | 0.09 | | $ | 1.04 |
Net income (loss) per common share — Diluted | | $ | 0.01 | | $ | 0.41 | | $ | 0.08 | | $ | 1.04 |
Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.1 million for each of the three and nine months ended March 31, 20172024 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 | |||
Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.3 million and was subsequently increased to $400.1 million effective February 1, 2018. As of Decemberfor the three and nine months ended March 31, 2017, the Company was in compliance with all covenants contained2023, respectively, were not included in the Facility,computation of diluted earnings per common share because the effect would have been anti-dilutive.
In addition, unvested performance-based restricted stock awards and no amounts were outstanding underunvested contingent restricted stock units that would not meet the Facility.
23
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Certain amounts on the unaudited condensed consolidated balance sheets are comprised of the following (in thousands):
| | | | | | |
|
| March 31, 2024 |
| June 30, 2023 | ||
Prepaid expenses and other current assets: | | | | | | |
Other receivables(1) | | $ | 2,576 | | $ | 18 |
Prepaid insurance | | | 311 | | | 727 |
Prepaid federal and state income taxes | | | 1,980 | | | 805 |
Carryback of EOR tax credit | | | 347 | | | 347 |
Advances to operators | | | 594 | | | — |
Prepaid other | | | 467 | | | 380 |
Total prepaid expenses and other current assets | | $ | 6,275 | | $ | 2,277 |
| | | | | | |
Other assets: | | | | | | |
Deposit | | $ | 1,158 | | $ | 1,158 |
Right of use asset under operating lease | | | 160 | | | 183 |
Total other assets | | $ | 1,318 | | $ | 1,341 |
| | | | | | |
Accrued liabilities and other: | | | | | | |
Accrued payables | | $ | 2,789 | | $ | 3,005 |
Accrued capital expenditures | | | — | | | 167 |
Accrued incentive and other compensation | | | 902 | | | 941 |
Accrued royalties payable | | | 625 | | | 977 |
Accrued taxes other than federal and state income tax | | | 1,166 | | | 739 |
Accrued severance | | | — | | | 81 |
Accrued settlements on derivative contracts | | | 94 | | | — |
Operating lease liability | | | 97 | | | 59 |
Asset retirement obligations due within one year | | | 158 | | | 55 |
Accrued - other | | | 154 | | | 3 |
Total accrued liabilities and other | | $ | 5,985 | | $ | 6,027 |
| (1) | At March 31, 2024, includes $2.6 million receivable related to customary purchase price adjustments related to the SCOOP/STACK Acquisitions. See Note 3, “Acquisitions” for a further discussion. |
Note 14. Subsequent Events
Dividend Declaration
On May 6, 2024, the Company incurred $168,972declared a quarterly cash dividend of debt issuance costs. Such costs were capitalized in Other Assets$0.120 per share of common stock to shareholders of record on June 14, 2024 and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $70,334 aspayable on June 28, 2024.
24
| Twelve months ended December 31, | |||
| 2018 | $ | 73,073 | |
| 2019 (through May) | $ | 30,447 | |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Commonly Used Terms
“Current quarter"quarter” refers to the three months ended DecemberMarch 31, 2017, the Company's second2024, our third quarter of fiscal 2018.
“Year-ago quarter” refers to the three months ended September 30, 2017, the Company's firstMarch 31, 2023, our third quarter of fiscal 2018.year 2023.
Executive Overview
General
Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.
Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; as well as small overriding royalty interests in four onshore central Texas wells.
Our non-operated interests in the SCOOP and STACK plays, an oil and natural gas producing property in the Anadarko basin, consist of approximately 3% average net working interest and approximately 2% average net revenue interests located on approximately 3,700 net acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.
Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross acres associated with ten development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information.
Our non-operated interests in the Jonah Field, a natural gas and NGL producing field in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres. The properties are operated by Jonah Energy, an established operator in the geographic region.
Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North
25
Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.
Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.
Our non-operated interests in the Delhi Field, a CO2-EOR project producing oil and NGLs, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”), which was acquired by Exxon Mobil Corporation during the current fiscal year. The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
Recent Developments
SCOOP/STACK Acquisitions
On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement process expected to occur during the fourth quarter of fiscal 2024.
The acquired assets consist of an average net working interest of approximately 3% in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.
Senior Secured Credit Facility
On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.
26
Appointment of Chief Accounting Officer
On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.
Share Repurchase Program
In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.
Chaveroo Oilfield Participation Agreement
On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).
Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.
During the three months ended December 31, 2016, the Company's second quarterSeptember 30, 2023, we paid total cash consideration of fiscal 2017.
Risks and uncertainties
The global economy was deeply impacted by the effects of 2017.
| 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 | % | |||
In addition, the conflict in the Middle East, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which have further enhanced volatility in global commodity prices.
27
At times, we do maintain cash balances in excess of basis during the current year.
The Federal Reserve has taken actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize.
Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.
Liquidity and Capital Resources
As of March 31, 2024, we had $25.7 million and $23.0$3.1 million in cash and cash equivalents and $42.5 million outstanding on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at December 31, 2017 and June 30, 2017, respectively.
The Senior Secured Credit Facility has a maximum capacity of $50.0 million. The Facility had $10.0 million ofsubject to a borrowing base availabilitydetermined by the lender based on December 31, 2017the value of our oil and June 30, 2017, respectively. Effective February 1, 2018, thenatural gas properties. The Senior Secured Credit Facility has a current borrowing base and availability under theof $50.0 million, with $42.5 million drawn as of March 31, 2024. The Senior Secured Credit Facility was expanded to $40.0 million. There have been no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets.
Borrowings bear interest, at the Company'sour option, at either LIBORthe SOFR plus 2.75%2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. For the nine months ended March 31, 2024 and 2023, the weighted average interest on our borrowings was 8.13% and 5.25%, respectively.The Senior Secured Credit Facility contains covenants that requirerequiring the maintenance of (i) a total leverage ratio of not more than 3.03.00 to 1.0,1.00, (ii) a debt service coveragecurrent ratio of not less than 1.11.00 to 1.01.00, and (iii) a consolidated tangible net worth of not less than $40$40.0 million, each as defined in the Senior Secured Credit Facility. The FacilityIt also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of DecemberMarch 31, 2017, the Company was2024, we were in compliance with all covenants containedunder the Senior Secured Credit Facility.
On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.
On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral
28
Value, as defined in the Facility.
On February 7, 2022, we funded our operationsentered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and cash dividends with cash generated from operationsnatural gas production over that period.
On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and our cash balance increased $2.7 million during that period. Asadded a hedging covenant whereby we must hedge a minimum of December 31, 2017, our working capital25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was $27.6 million, an increase of $4.2 million over working capital of $23.4 million at June 30, 2017.
We have historically funded our operations through cash from operations and working capital.capital and utilized our credit facility for property acquisitions. Our primary source of cash from operations is the sale of produced crude oil, and natural gas, liquids production.and NGLs. A portion of these cash flows areis used to fund our capital expenditures. While weexpenditures and pay cash dividends to shareholders. We expect to continue to expendfund near-future 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 developmentexpenditures with cash flows from operating 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 orand other transactions. WeIn addition to cash on hand, we have access to at least $40 millionthe undrawn portion of availabilitythe borrowing base available under our senior secured credit facility if required. In addition weSenior Secured Credit Facility, totaling $7.5 million as of March 31, 2024. We also have an effective shelf registration statement with Securities and Exchange Commissionthe SEC under which we may issue up to $500.0 million of new debt or equity securities. If 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 so at this time.
Our other significant use of cash is our on-going dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we2013. We have since paid seventeen42 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 termlong-term goal to increase our dividends over time, as appropriate. In February 2018,On May 6, 2024, the Board of Directors declared an increasea quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.
On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the quarterlyopen market through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is a complimentary option to the existing dividend policy and investment opportunities, and is a tax efficient means to further improve shareholder return.
In December 2022, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the three and nine months ended March 31, 2023, 0.6 million shares of our common stock dividendwere repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These shares were subsequently cancelled.
In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from $0.075 per sharetime to $0.10 per share, effective withtime to the dividend payment in March 2018. The Board reviewsextent we determine changes are necessary to achieve the quarterly dividend rate in lightintended objectives of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing
29
repurchase program. During the sixthree and nine months ended DecemberMarch 31, 2017,2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.
Capital Expenditures
During the nine months ended March 31, 2024, we incurred $1.4$9.4 million ofin capital expenditures, a majority of which was spent at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $0.5 million for Phase V infrastructure, $0.4 million for CO
Based on discussions with our operators, we expect capital workover projects to commence duringcontinue in all the quarter ended March 31, 2018. The infill program has a revised estimated net cost of $4.7 million, the majority of which is expectedfields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be incurred in the remainderrange of the current fiscal year. The program consists of five new CO
Funding for our anticipated capital expenditures at Delhi over the next fiscal yearnear-term is expected to be met from cash flows from operations and current working capital.
Full Cost Pool Ceiling Test and Proved Undeveloped Reserves
Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&Adepletion, depreciation, and amortization and related deferred taxes, are limited to (the full cost valuation “ceiling”): the estimated future net cash flows from proved oil and natural 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 theas adjusted for related income tax effect related to the differences between the book and tax basis of the properties.effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price received for our petroleum products during the twelve month12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of March 31, 2024 were $77.64 per barrel of oil, $2.44 per MMBtu of natural gas and $29.88 per barrel of NGLs. As of March 31, 2024, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity prices drop below the averageprice levels were to substantially decline from the past twelve months,12-month average first day of the month pricing levels as of March 31, 2024 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future ceiling test calculations would be adversely affected.quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at March 31, 2024, while all other factors remained constant, would not have generated an impairment.
Overview of Cash Flow Activities
| | | | | | | | | |
| | Nine Months Ended March 31, | | | | ||||
|
| 2024 |
| 2023 |
| Change | |||
Cash flows provided by operating activities | | $ | 14,742 | | $ | 51,719 | | $ | (36,977) |
Cash flows used in investing activities | | | (52,141) | | | (4,265) | | | (47,876) |
Cash flows provided by (used in) financing activities | | | 29,432 | | | (37,347) | | | 66,779 |
Net increase (decrease) in cash and cash equivalents | | $ | (7,967) | | $ | 10,107 | | $ | (18,074) |
Cash provided by operating activities for the nine months ended March 31, 2024 decreased $37.0 million compared to the nine months ended March 31, 2023 primarily due to a decrease in revenues. Total revenues decreased $45.7 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our
30 2017 included 544 MBOE
average realized price per barrel of oil equivalent (“BOE”) decreased $19.71, or 35.8% from the prior year period. Refer to “Results of Operations” below for further information.
Cash used in investing activities for the nine months ended March 31, 2024 increased $47.9 million compared to the nine months ended March 31, 2023 primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and $3.2completion of three new wells in the Chaveroo Field. As of the quarter ended March 31, 2024, we have paid approximately $43.8 million for the SCOOP/STACK Acquisitions and have accrued estimated preliminary purchase price adjustments of $3.3 million related to net cash flows earned on the properties from the effective date to the closing date to arrive a net purchase price of $40.5 million.
Net cash flows provided by financing activities for the nine months ended March 31, 2024 were $29.4 million compared to net cash flows used in financing activities of $37.3 million for the nine months ended March 31, 2023. In the current year period, we borrowed $42.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions which was partially offset by $12.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of future development costs associated with a planned infill drillingborrowings outstanding under our Senior Secured Credit Facility, $12.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program.
31
Results of Operations
Three Months Ended March 31, 2024 and 1,564 MBOE2023
We reported net income of reserves$0.3 million and $10.9$14.0 million for the three months ended March 31, 2024 and 2023, respectively. The following table summarizes the comparison of future development costs associated withfinancial information for the Phase V developmentperiods presented:
| | | | | | | | | | | | |
| | Three Months Ended | | | | | | | ||||
| | March 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2024 | | 2023 |
| Variance |
| Variance % | ||||
Net income (loss) | | $ | 289 | | $ | 13,957 | | $ | (13,668) | | (97.9) | % |
Revenues: | | | | | | | | | | | | |
Crude oil | | | 14,538 | | | 11,799 | | | 2,739 | | 23.2 | % |
Natural gas | | | 5,860 | | | 21,598 | | | (15,738) | | (72.9) | % |
Natural gas liquids | | | 2,627 | | | 3,470 | | | (843) | | (24.3) | % |
Total revenues | | | 23,025 | | | 36,867 | | | (13,842) | | (37.5) | % |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | | 1,035 | | | 1,821 | | | (786) | | (43.2) | % |
Ad valorem and production taxes | | | 1,458 | | | 1,642 | | | (184) | | (11.2) | % |
Other lease operating costs | | | 10,131 | | | 10,107 | | | 24 | | 0.2 | % |
Depletion, depreciation, and accretion: | | | | | | | | | | | | |
Depletion of full cost proved oil and natural gas properties | | | 5,532 | | | 3,098 | | | 2,434 | | 78.6 | % |
Accretion of asset retirement obligations | | | 368 | | | 285 | | | 83 | | 29.1 | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 1,868 | | | 1,814 | | | 54 | | 3.0 | % |
Stock-based compensation | | | 549 | | | 453 | | | 96 | | 21.2 | % |
Other income (expense): | | | | | | | | | | | | |
Net gain (loss) on derivative contracts | | | (1,183) | | | 270 | | | (1,453) | | (538.1) | % |
Interest and other income | | | 63 | | | 13 | | | 50 | | 384.6 | % |
Interest expense | | | (518) | | | (32) | | | (486) | | 1,518.8 | % |
Income tax (expense) benefit | | | (157) | | | (3,941) | | | 3,784 | | (96.0) | % |
| | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Crude oil (MBBL) | | | 199 | | | 167 | | | 32 | | 19.2 | % |
Natural gas (MMCF) | | | 2,115 | | | 2,204 | | | (89) | | (4.0) | % |
Natural gas liquids (MBBL) | | | 104 | | | 104 | | | — | | - | % |
Equivalent (MBOE)(1) | | | 656 | | | 638 | | | 18 | | 2.8 | % |
Average daily production (BOEPD)(1) | | | 7,209 | | | 7,089 | | | 120 | | 1.7 | % |
| | | | | | | | | | | | |
Average price per unit(2): | | | | | | | | | | | | |
Crude oil (BBL) | | $ | 73.06 | | $ | 70.65 | | $ | 2.41 | | 3.4 | % |
Natural gas (MCF) | | | 2.77 | | | 9.80 | | | (7.03) | | (71.7) | % |
Natural Gas Liquids (BBL) | | | 25.26 | | | 33.37 | | | (8.11) | | (24.3) | % |
Equivalent (BOE)(1) | | | 35.10 | | | 57.79 | | | (22.69) | | (39.3) | % |
| | | | | | | | | | | | |
Average cost per unit: | | | | | | | | | | | | |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | $ | 1.58 | | $ | 2.85 | | | (1.27) | | (44.6) | % |
Ad valorem and production taxes | | | 2.22 | | | 2.57 | | | (0.35) | | (13.6) | % |
Other lease operating costs | | | 15.44 | | | 15.84 | | | (0.40) | | (2.5) | % |
Depletion of full cost proved oil and natural gas properties | | | 8.43 | | | 4.86 | | | 3.57 | | 73.5 | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 2.85 | | | 2.84 | | | 0.01 | | 0.4 | % |
Stock-based compensation | | | 0.84 | | | 0.71 | | | 0.13 | | 18.3 | % |
| (1) | Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
| (2) | Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. |
32
Revenues
Crude oil, natural gas and NGL revenues were $23.0 million and $36.9 million for the three months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the easterndecrease in our average realized price per BOE partially offset by an increase in our crude oil sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended March 31, 2024 decreased approximately $22.69 per BOE, or 39.3%, compared to the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 71.7% from the prior year period, which was the largest portion of the field. The objectivedriver of the infill drilling programdecrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $20.31 per MCF in the prior year period compared to $3.94 per MCF in the current year quarter. Average daily equivalent production increased 1.7% from 7,089 BOEPD in the prior year period to 7,209 BOEPD in the current period primarily due to the acquisitions of non-operated working interests in the SCOOP/STACK in the latter part of February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased current quarter production by approximately 1,020 BOEPD. These increases were partially offset by a decrease in production at our Barnett Shale properties. We began experiencing production declines and downtime in April 2023 at Barnett Shale. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes.
Lease Operating Costs
Ad valorem and production taxes were $1.5 million and $1.6 million for the three months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.22 per BOE and $2.57 per BOE for the three months ended March 31, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to increasedecreases in realized natural gas and NGLs revenues described above, as production taxes are based on sales at the wellhead.
The following table summarizes CO2 costs per Mcf and recover reserves whichCO2 volumes for the three months ended March 31, 2024 and 2023. CO2 purchase costs are not believed to be effectively produciblefor the Delhi Field. Under our contract with the existing well configuration. Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.
| | | | | | | | | | | | | ||||||
| | Three Months Ended | | | | | | | ||||||||||
| | March 31, | | | | | | | ||||||||||
|
| 2024 |
| 2023 |
| Variance |
| Variance % | ||||||||||
CO2 costs per MCF | | $ | 0.92 | | $ | 0.92 | | $ | — | | — | % | ||||||
CO2 volumes (MMCF per day, gross) | | | 52.1 | | | 91.7 | | | (39.6) | | (43.2) | % | ||||||
The project includes both acceleration$0.8 million decrease in CO2 costs for the three months ended March 31, 2024 was primarily due to a 43.2% decrease in purchased CO2 volumes, which was primarily due to the suspension of productionCO2 purchases at the end of February 2024 due to maintenance on the CO2 pipeline. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $1.58 per BOE and $2.85 per BOE for the three months ended March 31, 2024 and 2023, respectively.
Other lease operating costs were primarily flat, compared to the prior year period. On a per unit basis, other lease operating costs decreased slightly to $15.44 per BOE for the three months ended March 31, 2024 from $15.84 per BOE in the year-ago quarter. The largest decrease in operating costs was at our Barnett Shale properties offset by an additional LOE incurred as a result of our SCOOP/STACK Acquisitions. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are experiencing lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges.
33
Depletion of Full Cost Proved Oil and Natural Gas Properties
Depletion expense increased $2.4 million or 78.6% from $3.1 million to $5.5 million for the three months ended March 31, 2024 primarily due to an increase in ultimate reserve recoverythe depletion rate. On a per unit basis, depletion expense was $8.43 per BOE and has been recorded as a proved undeveloped project.$4.86 per BOE for the three months ended March 31, 2024 and 2023, respectively. 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 third quarter of fiscal 2018. The timingdepletion rate of our Phase V development is dependentunit of production calculation increased due to decreases in part onproved reserve volumes as well as increases in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since March 31, 2023. Our proved reserves volumes have decreased since the results and CO2 requirement of the infill program. At present, we expectprior year period primarily due to begin this development in calendar 2019.
| 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 | % | ||||||
General and $7,697 of other depreciationAdministrative Expenses
General and amortizationadministrative expenses for the three months ended March 31, 2024 increased minimally over the prior year period. General and administrative expenses were $1.9 million for the three months ended March 31, 2024 compared to $1.8 million for the prior year period. The increase primarily relates to an increase in salary and employee benefits due to additional personnel added as additional assets were acquired. On a per unit basis, general and administrative expenses were $2.85 per BOE and $2.84 per BOE for the three months ended March 31, 2024 and 2023, respectively.
Stock-based Compensation Expense
Stock-based compensation expense for the three months ended DecemberMarch 31, 20172024 remained flat at $0.5 million for each period.
34
Net Gain (Loss) on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and 2016,natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our SCOOP/STACK Acquisitions in the current quarter and our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter and an unrealized loss on the mark-to-market of our hedges, respectively.
| | | | | | | | | | | | |
| | Three Months Ended | | | | | | | ||||
| | March 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2024 |
| 2023 |
| Variance |
| Variance % | ||||
Realized gain (loss) on derivative contracts | | $ | (120) | | $ | 465 | | $ | (585) | | (125.8) | % |
Unrealized gain (loss) on derivative contracts | | | (1,063) | | | (195) | | | (868) | | 445.1 | % |
Total net gain (loss) on derivative contracts | | $ | (1,183) | | $ | 270 | | $ | (1,453) | | (538.1) | % |
| | | | | | | | | | | | |
Average realized crude oil price per BBL | | $ | 73.06 | | $ | 70.65 | | $ | 2.41 | | 3.4 | % |
Cash effect of oil derivative contracts per BBL | | | (0.60) | | | — | | | (0.60) | | — | % |
Crude oil price per BBL (including impact of realized derivatives) | | $ | 72.46 | | $ | 70.65 | | $ | 1.81 | | 2.6 | % |
| | | | | | | | | | | | |
Average realized natural gas price per MCF | | $ | 2.77 | | $ | 9.80 | | $ | (7.03) | | (71.7) | % |
Cash effect of natural gas derivative contracts per MCF | | | — | | | 0.21 | | | (0.21) | | (100) | % |
Natural gas price per MCF (including impact of realized derivatives) | | $ | 2.77 | | $ | 10.01 | | $ | (7.24) | | (72.3) | % |
Interest Expense
Interest expense increased $0.5 million for the three months ended DecemberMarch 31, 2017,2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current period.
Income Tax (Expense) Benefit
For the three months ended March 31, 2024, we generatedrecognized income tax expense of $0.2 million on net income before income taxes of $0.4 million compared to income tax expense of $3.9 million on net income before income taxes of $17.9 million for the three months ended March 31, 2023. The effective tax rates were 35.2% and 22.0% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.
35
Nine Months Ended March 31, 2024 and 2023
We reported net income of $9.9$2.8 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 $8.5and $35.1 million for the year-ago quarter.nine months ended March 31, 2024 and 2023, respectively. The $7.6following table summarizes the comparison of financial information for the periods presented:
| | | | | | | | | | | | |
| | Nine Months Ended | | | | | | | ||||
| | March 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2024 |
| 2023 |
| Variance |
| Variance % | ||||
Net income (loss) | | $ | 2,845 | | $ | 35,051 | | $ | (32,206) | | (91.9) | % |
Revenues: | | | | | | | | | | | | |
Crude oil | | | 38,913 | | | 40,062 | | | (1,149) | | (2.9) | % |
Natural gas | | | 17,943 | | | 58,816 | | | (40,873) | | (69.5) | % |
Natural gas liquids | | | 7,794 | | | 11,462 | | | (3,668) | | (32.0) | % |
Total revenues | | | 64,650 | | | 110,340 | | | (45,690) | | (41.4) | % |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | | 4,241 | | | 6,027 | | | (1,786) | | (29.6) | % |
Ad valorem and production taxes | | | 4,008 | | | 7,001 | | | (2,993) | | (42.8) | % |
Other lease operating costs | | | 28,616 | | | 34,699 | | | (6,083) | | (17.5) | % |
Depletion, depreciation, and accretion: | | | | | | | | | | | | |
Depletion of full cost proved oil and natural gas properties | | | 13,680 | | | 9,598 | | | 4,082 | | 42.5 | % |
Accretion of asset retirement obligations | | | 1,080 | | | 841 | | | 239 | | 28.4 | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 5,937 | | | 6,165 | | | (228) | | (3.7) | % |
Stock-based compensation | | | 1,585 | | | 1,155 | | | 430 | | 37.2 | % |
Other income (expense): | | | | | | | | | | | | |
Net gain (loss) on derivative contracts | | | (1,183) | | | 513 | | | (1,696) | | (330.6) | % |
Interest and other income | | | 283 | | | 26 | | | 257 | | 988.5 | % |
Interest expense | | | (584) | | | (404) | | | (180) | | 44.6 | % |
Income tax (expense) benefit | | | (1,174) | | | (9,938) | | | 8,764 | | (88.2) | % |
| | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Crude oil (MBBL) | | | 519 | | | 501 | | | 18 | | 3.6 | % |
Natural gas (MMCF) | | | 6,091 | | | 7,065 | | | (974) | | (13.8) | % |
Natural gas liquids (MBBL) | | | 295 | | | 325 | | | (30) | | (9.2) | % |
Equivalent (MBOE)(1) | | | 1,829 | | | 2,004 | | | (175) | | (8.7) | % |
Average daily production (BOEPD)(1) | | | 6,651 | | | 7,314 | | | (663) | | (9.1) | % |
| | | | | | | | | | | | |
Average price per unit(2): | | | | | | | | | | | | |
Crude oil (BBL) | | $ | 74.98 | | $ | 79.96 | | $ | (4.98) | | (6.2) | % |
Natural gas (MCF) | | | 2.95 | | | 8.32 | | | (5.37) | | (64.5) | % |
Natural Gas Liquids (BBL) | | | 26.42 | | | 35.27 | | | (8.85) | | (25.1) | % |
Equivalent (BOE)(1) | | | 35.35 | | | 55.06 | | | (19.71) | | (35.8) | % |
| | | | | | | | | | | | |
Average cost per unit: | | | | | | | | | | | | |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
CO2 costs | | $ | 2.32 | | $ | 3.01 | | | (0.69) | | (22.9) | % |
Ad valorem and production taxes | | | 2.19 | | | 3.49 | | | (1.30) | | (37.2) | % |
Other lease operating costs | | | 15.65 | | | 17.31 | | | (1.66) | | (9.6) | % |
Depletion of full cost proved oil and natural gas properties | | | 7.48 | | | 4.79 | | | 2.69 | | 56.2 | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 3.25 | | | 3.08 | | | 0.17 | | 5.5 | % |
Stock-based compensation | | | 0.87 | | | 0.58 | | | 0.29 | | 50.0 | % |
| (1) | Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
| (2) | Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. |
36
Revenues
Crude oil, natural gas and NGL revenues were $64.7 million earnings increase reflectsand $110.3 million for the nine months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a $2.5 million revenue increase, a $6.4 million declinedecrease in income taxes primarily attributable toour sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the 2017 Tax Cutsnine months ended March 31, 2024 decreased approximately $19.71 per BOE, or 35.8%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and Jobs Act,supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 64.5% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially offset by $1.4 millionattributed to the prior year period benefit of higher operating expenses.
Lease Operating Costs
Ad valorem and production taxes were $4.0 million and $7.0 million for the nine months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.19 per BOE and $3.49 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas prices as well as decreased production volumes fromdescribed above as production taxes are based on sales at the year-ago quarter, togetherwellhead.
The following table summarizes CO2 costs per Mcf and CO2 volumes for the nine months ended March 31, 2024 and 2023. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.
| | | | | | | | | | | | | ||||||
| | Nine Months Ended | | | | | | | ||||||||||
| | March 31, | | | | | | | ||||||||||
|
| 2024 |
| 2023 |
| Variance |
| Variance % | ||||||||||
CO2 costs per MCF | | $ | 0.97 | | $ | 1.01 | | $ | (0.04) | | (4.0) | % | ||||||
CO2 volumes (MMCF per day, gross) | | | 67.0 | | | 90.8 | | | (23.8) | | (26.2) | % | ||||||
The $1.8 million decrease in CO2 costs for the nine months ended March 31, 2024 was primarily due to a 26.2% decrease in purchased CO2 volumes combined with a 16% increase4.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price and NGL prices from $46.66 per equivalent barrelthe suspension of CO2 purchases at the end of February 2024 due to $54.30 per equivalent barrelmaintenance on the CO2 pipeline. CO2 volumes injected were also reduced compared to prior year period due to a reduction in CO2 purchase nominations and higher ambient temperatures in the current quarter. All of our revenues forDelhi Field during 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 infiscal year. In the prior year stabilized at lower ratesperiod, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the current quarter. Net NGL production averaged 283 BOEPDfield and the field’s recycle facilities provide the other 80%. We do not have any ownership in the current quarter, at an average sales price of $33.85CO2 pipeline which is owned and operated by Denbury. On a per barrel. Thereunit basis, CO2 costs were no NGL sales in the year-ago quarter as NGL plant production began in January 2017.
Other lease operating costs decreased $6.1 million, or 27%17.5%, increase fromcompared to the year-ago quarter,prior year period primarily due to to higher CO
37
significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi working interest volumes, production costs were $18.75Field, we have seen lower electricity charges due to lower commodity prices.
Depletion of Full Cost Proved Oil and Natural Gas Properties
Depletion expense increased $4.1 million or 42.5% from $9.6 million to $13.7 million for the nine months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.48 per BOE of which $8.55and $4.79 per BOE was CO2 cost. These costs per equivalent barrel excludefor the nine months ended March 31, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes fromas well as increase in our royalty interestsdepletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced, combined with a reduction in the Delhi field, which bear almost no production costs, and are therefore higher thanSEC prices used for calculating proved reserves since the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”).
General and administrative expenses for the nine months ended March 31, 2024 decreased $0.2 million, or 3.7%, to $5.9 million compared to $6.2 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.25 per BOE and $3.08 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period.
Stock-based Compensation Expense
Stock-based compensation expense for the nine months ended March 31, 2024 increased $0.4 million or 34%, to $1.7$1.6 million compared to $1.2 million for the three months ended December 31, 2017prior year period. The increase is primarily due to the addition of new personnel, including our CEO and COO added since the prior year period and the associated new awards granted during the current year period.
38
Net Gain (Loss) on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of $0.2 millionour SCOOP/STACK Acquisitions in the current quarter and our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of higher non-cash stock compensation expense, $0.1 million for litigation costsour production. The increase in commodity prices since entering into the hedges and $0.1 million for due diligence costs associated with property evaluations.
| | | | | | | | | | | | |
| | Nine Months Ended | | | | | | | ||||
| | March 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) |
| 2024 |
| 2023 |
| Variance |
| Variance % | ||||
Realized gain (loss) on derivative contracts | | $ | (120) | | $ | (1,481) | | $ | 1,361 | | (91.9) | % |
Unrealized gain (loss) on derivative contracts | | | (1,063) | | | 1,994 | | | (3,057) | | (153.3) | % |
Total net gain (loss) on derivative contracts | | $ | (1,183) | | $ | 513 | | $ | (1,696) | | (330.6) | % |
| | | | | | | | | | | | |
Average realized crude oil price per BBL | | $ | 74.98 | | $ | 79.96 | | $ | (4.98) | | (6.2) | % |
Cash effect of oil derivative contracts per BBL | | | (0.23) | | | (0.49) | | | 0.26 | | (53.1) | % |
Crude oil price per BBL (including impact of realized derivatives) | | $ | 74.75 | | $ | 79.47 | | $ | (4.72) | | (5.9) | % |
| | | | | | | | | | | | |
Average realized natural gas price per MCF | | $ | 2.95 | | $ | 8.32 | | $ | (5.37) | | (64.5) | % |
Cash effect of natural gas derivative contracts per MCF | | | — | | | (0.17) | | | 0.17 | | (100) | % |
Natural gas price per MCF (including impact of realized derivatives) | | $ | 2.95 | | $ | 8.15 | | $ | (5.20) | | (63.8) | % |
Interest Expense
Interest expense increased development costs.
| 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 | % | ||||||
Income Tax (Expense) Benefit
For the Delhi field, as well as virtually allnine months ended March 31, 2024, we recognized income tax expense of our revenues from$1.2 million on net income before income taxes of $4.0 million compared to income tax expense of $9.9 million on net income before income taxes of $45.0 million for the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD fromnine months ended March 31, 2023. The effective tax rates were 29.2% and 22.1% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to 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 beganprojected state income taxes have become a larger component of our overall income tax expense during the period.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in January 2017.
39
consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K 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 quarterfiscal year ended June 30, 2015, there can be no assurance that such prices will continue to prevail or trend upward.
Item 3.
Derivative Instruments and Hedging Activity
We are exposed to various risks, forincluding energy commodity price risk, such as price differentials between the three months ended December 31, 2017, did not change materially fromNYMEX commodity price and the disclosures in Item 7A ofindex price at the location where our Annual Report on Form 10-K for the year ended June 30, 2017.
We are exposed to market risk on our assessmentopen derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2024 and 2023, we did not post collateral. We account for our derivative activities under the provisions of such risk.
Interest Rate Risk
We currently have only a small exposureare exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current policies,practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Item 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms and that suchforms. This information is accumulated and communicated to this Company’sour management, including our ChiefPrincipal Executive Officer and ChiefPrincipal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
As required by Securities and Exchange CommissionSEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’sour management, including our ChiefPrincipal Executive Officer and ChiefPrincipal 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)15(d)-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 ChiefPrincipal Executive Officer and ChiefPrincipal Financial Officer concluded that as of DecemberMarch 31, 20172024 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 CommissionSEC rules and forms.
40
Under the supervision and with the participation of the Company’sour management, including its Chiefour Principal Executive Officer and ChiefPrincipal Financial Officer, during the quarter ended DecemberMarch 31, 2017,2024, we have determined that there hashave been no changes in our internal controlscontrol over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controlscontrol over financial reporting.
Item 1. LEGAL PROCEEDINGS
See Note 10, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in certainItem 1. Condensed Consolidated Financial Statements (Unaudited) for a description of any 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 —
Item 1A. RISK FACTORS
Our Annual Report on Form 10-K for the year ended June 30, 20172023 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.
Item 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
The table below summarizes information about the Company's purchases of its equity securities during the quarterthree months ended DecemberMarch 31, 2017.
| | | | | | | | | | |
| | | | | | (c) Total number | | (d) Maximum dollar value | ||
| | (a) Total number | | | | of shares | | of shares that may yet be | ||
| | of shares | | | | purchased as part | | purchased under the | ||
| | purchased and | | (b) Average price | | of public announced | | plans or programs | ||
Period | | received (1) | | paid per share (1) | | plans or programs(2) | | (in thousands)(2) | ||
January 2024 | | 400 | | $ | 5.50 | | 400 | | $ | 21,150 |
February 2024 | | 150,799 | | | 5.35 | | 140,272 | | | 20,403 |
March 2024 | | 741 | | | 5.90 | | — | | | 20,403 |
| 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 | ||||
| (1) | During the three months ended March 31, 2024, all of the shares received outside of publicly announced plans or programs were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. |
| (2) | On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, the Company’s capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice. In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. |
41
Contents
Not applicable.
Not applicable.
Item 5. OTHER INFORMATION
None.
Item 6. EXHIBITS
The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.
| | | |
|---|---|---|---|
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
3.1 | | ||
3.3 | | ||
10.11* | | ||
10.12* | | ||
10.13* | | ||
10.2.11* | | ||
31.1** | | ||
31.2** | | ||
32.1** | | ||
32.2** | | ||
101.INS* | | Inline XBRL Instance Document | |
101.SCH* | | Inline XBRL Taxonomy Extension Schema Document | |
101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | | Inline XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document | |
104* | | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
* Attached hereto.
** Furnished herewith.
42
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 | |||
Date: May 8, 2024 | | By: | /s/ KELLY W. LOYD |
| | | |
Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director | |||
| | By: | /s/ RYAN STASH |
| | | Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer |
43