UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31,June 30, 2020
OR
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-16317
CONTANGO OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
TEXAS |
| 95-4079863 |
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(State or other jurisdiction of |
| (IRS Employer |
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717 TEXAS AVENUE, SUITE 2900 HOUSTON, TEXAS | | 77002 |
(Address of principal executive offices) | | (Zip Code) |
(713) 236-7400
(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, Par Value $0.04 per share | MCF | 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 ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated 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 ☐ No ☒
The total number of shares of common stock, par value $0.04 per share, outstanding as of June 17,August 14, 2020 was 131,689,480.
Explanatory Note
On March 25, 2020, the U.S. Securities and Exchange Commission issued an order under Section 36 (Release No. 34-88465) of the Securities Exchange Act of 1934 (the “Exchange Act”) granting exemptions from specified provisions of the Exchange Act and certain rules thereunder (the “Order”). The Order provides conditional relief to public companies that are unable to timely comply with their filing obligations as a result of the novel coronavirus (“COVID-19”) pandemic. Contango Oil & Gas Company (the “Company”) relied on the Order to delay the filing of this Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, due to circumstances related to COVID-19. The Company’s headquarters and other accounting offices are located in areas of the United States that have been under “lock-down” or “stay at home” orders implemented in response to the COVID-19 pandemic. The Company’s accounting personnel have been working remotely since the orders were implemented and have also been operating under travel and work restrictions stemming from the COVID-19 pandemic. As a result, the Company’s accounting workflow and its ability to complete necessary review processes and procedures with respect to its financial statements were negatively impacted. Accordingly, the Company required additional time to prepare and finalize this report.
133,038,930.
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE THREESIX MONTHS ENDED MARCH 31,JUNE 30, 2020
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PART I—FINANCIAL INFORMATION | ||||
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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Unless the context requires otherwise or unless otherwise noted, all references in this Quarterly Report on Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its subsidiaries.
32
Item 1. Consolidated Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
(in thousands, except number of shares)
| | | | | | | | | | | | | | |
| | March 31, | | December 31, | | | June 30, | | December 31, | | ||||
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| 2020 |
| 2019 |
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| 2020 |
| 2019 |
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| | | | | | | ||||||||
| | (unaudited) | | | | (unaudited) | | | | | ||||
CURRENT ASSETS: | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 1,685 | | $ | 1,624 | | | $ | 404 | | $ | 1,624 | |
Accounts receivable, net | | | 28,565 | | | 39,567 | | | | 25,672 | | | 39,567 | |
Prepaid expenses | | | 1,436 | | | 1,191 | | | | 1,363 | | | 1,191 | |
Current derivative asset | | | 30,980 | | | 3,819 | | | | 16,826 | | | 3,819 | |
Inventory | | | 187 | | | 150 | | | | 1,710 | | | 186 | |
Deposits and other | | | 7,106 | | | 36 | | |||||||
Total current assets | | | 69,959 | | | 46,387 | | | | 45,975 | | | 46,387 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | |
Natural gas and oil properties, successful efforts method of accounting: | | | | | | | | |||||||
Oil and natural gas properties, successful efforts method of accounting: | | | | | | | | |||||||
Proved properties | | | 1,314,886 | | | 1,306,916 | | | | 1,315,040 | | | 1,306,916 | |
Unproved properties | | | 24,002 | | | 27,619 | | | | 20,901 | | | 27,619 | |
Other property and equipment | | | 1,629 | | | 1,655 | | | | 1,668 | | | 1,655 | |
Accumulated depreciation, depletion and amortization | | | (1,202,643) | | | (1,045,070) | | | | (1,206,957) | | | (1,045,070) | |
Total property, plant and equipment, net | | | 137,874 | | | 291,120 | | | | 130,652 | | | 291,120 | |
OTHER NON-CURRENT ASSETS: | | | | | | | | | | | | | | |
Investments in affiliates | | | 7,052 | | | 6,766 | | | | 6,879 | | | 6,766 | |
Long-term derivative asset | | | 9,474 | | | 357 | | | | 4,395 | | | 357 | |
Right-of-use lease assets | | | 5,305 | | | 5,885 | | | | 5,691 | | | 5,885 | |
Debt issuances costs | | | 3,135 | | | 3,311 | | |||||||
Debt issuance costs | | | 1,939 | | | 3,311 | | |||||||
Total other non-current assets | | | 24,966 | | | 16,319 | | | | 18,904 | | | 16,319 | |
TOTAL ASSETS | | $ | 232,799 | | $ | 353,826 | | | $ | 195,531 | | $ | 353,826 | |
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CURRENT LIABILITIES: | | | | | | | | | | | | | | |
Accounts payable and accrued liabilities | | $ | 83,742 | | $ | 104,593 | | | $ | 77,143 | | $ | 104,593 | |
Current derivative liability | | | 534 | | | 3,951 | | | | 908 | | | 3,951 | |
Current asset retirement obligations | | | 1,677 | | | 2,003 | | | | 2,291 | | | 2,003 | |
Total current liabilities | | | 85,953 | | | 110,547 | | | | 80,342 | | | 110,547 | |
NON-CURRENT LIABILITIES: | | | | | | | | | | | | | | |
Long-term debt | | | 82,768 | | | 72,768 | | | | 82,537 | | | 72,768 | |
Long-term derivative liability | | | 325 | | | 2,020 | | | | 917 | | | 2,020 | |
Asset retirement obligations | | | 50,626 | | | 49,662 | | | | 45,581 | | | 49,662 | |
Lease liabilities | | | 2,196 | | | 2,789 | | | | 2,156 | | | 2,789 | |
Deferred tax liability | | | 376 | | | — | | |||||||
Total non-current liabilities | | | 135,915 | | | 127,239 | | | | 131,567 | | | 127,239 | |
TOTAL LIABILITIES | | | 221,868 | | | 237,786 | | | | 211,909 | | | 237,786 | |
COMMITMENTS AND CONTINGENCIES (NOTE 11) | | | | | | | | |||||||
SHAREHOLDERS’ EQUITY: | | | | | | | | |||||||
Series C contingent convertible preferred stock, $0.04 par value, 2,700,000 shares authorized, issued and outstanding at March 31, 2020 and December 31, 2019 | | | 108 | | | 108 | | |||||||
Common stock, $0.04 par value, 200 million shares authorized, 129,062,631 shares issued and 129,005,827 shares outstanding at March 31, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019 | | | 5,151 | | | 5,148 | | |||||||
COMMITMENTS AND CONTINGENCIES (NOTE 12) | | | | | | | | |||||||
SHAREHOLDERS’ EQUITY (DEFICIT): | | | | | | | | |||||||
Series C contingent convertible preferred stock, $0.04 par value, no shares authorized, issued and outstanding at June 30, 2020 and 2,700,000 shares authorized, issued and outstanding at December 31, 2019 | | | — | | | 108 | | |||||||
Common stock, $0.04 par value, 400 million shares authorized, 132,067,369 shares issued and 131,996,757 shares outstanding at June 30, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019 | | | 5,271 | | | 5,148 | | |||||||
Additional paid-in capital | | | 472,078 | | | 471,778 | | | | 472,814 | | | 471,778 | |
Treasury shares at cost (56,804 shares at March 31, 2020 and 7,330 shares at December 31, 2019) | | | (175) | | | (18) | | |||||||
Treasury shares at cost (70,612 shares at June 30, 2020 and 7,330 shares at December 31, 2019) | | | (198) | | | (18) | | |||||||
Accumulated deficit | | | (466,231) | | | (360,976) | | | | (494,265) | | | (360,976) | |
Total shareholders’ equity | | | 10,931 | | | 116,040 | | |||||||
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 232,799 | | $ | 353,826 | | |||||||
Total shareholders’ equity (deficit) | | | (16,378) | | | 116,040 | | |||||||
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY (DEFICIT) | | $ | 195,531 | | $ | 353,826 | |
The accompanying notes are an integral part of these consolidated financial statements
43
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
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| | Three Months Ended | | | Three Months Ended | | Six Months Ended | | ||||||||||||
| | March 31, | | | June 30, | | June 30, | | ||||||||||||
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| 2020 |
| 2019 |
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| 2020 |
| 2019 | | 2020 |
| 2019 |
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| | (unaudited) | | | (unaudited) | | (unaudited) | | ||||||||||||
REVENUES: | | | | | | | | | | | | | | | | | | | | |
Oil and condensate sales | | $ | 22,782 | | $ | 6,406 | | | $ | 7,930 | | $ | 7,439 | | $ | 30,712 | | $ | 13,845 | |
Natural gas sales | | | 8,170 | | | 5,642 | | | | 6,618 | | | 3,857 | | | 14,789 | | | 9,499 | |
Natural gas liquids sales | | | 3,621 | | | 1,963 | | | | 3,294 | | | 1,466 | | | 6,915 | | | 3,429 | |
Total revenues | | | 34,573 | | | 14,011 | | | | 17,842 | | | 12,762 | | | 52,416 | | | 26,773 | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Operating expenses | | | 21,483 | | | 5,192 | | | | 17,139 | | | 5,694 | | | 38,621 | | | 10,886 | |
Exploration expenses | | | 398 | | | 224 | | | | 11,173 | | | 249 | | | 11,571 | | | 473 | |
Depreciation, depletion and amortization | | | 12,854 | | | 7,556 | | | | 5,092 | | | 7,573 | | | 17,946 | | | 15,129 | |
Impairment and abandonment of oil and gas properties | | | 145,878 | | | 587 | | | | — | | | 1,247 | | | 145,878 | | | 1,834 | |
General and administrative expenses | | | 5,425 | | | 5,005 | | | | 5,713 | | | 4,456 | | | 11,138 | | | 9,461 | |
Total expenses | | | 186,038 | | | 18,564 | | | | 39,117 | | | 19,219 | | | 225,154 | | | 37,783 | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Gain from investment in affiliates, net of income taxes | | | 286 | | | 30 | | |||||||||||||
Gain (loss) from sale of assets | | | 27 | | | (12) | | |||||||||||||
Gain (loss) from investment in affiliates, net of income taxes | | | (173) | | | 427 | | | 113 | | | 457 | | |||||||
Gain from sale of assets | | | 4,406 | | | 421 | | | 4,433 | | | 409 | | |||||||
Interest expense | | | (1,213) | | | (1,092) | | | | (2,151) | | | (1,079) | | | (3,365) | | | (2,171) | |
Gain (loss) on derivatives, net | | | 46,699 | | | (2,878) | | | | (8,804) | | | 2,065 | | | 37,895 | | | (813) | |
Other income (expense) | | | 805 | | | (86) | | |||||||||||||
Other income | | | 332 | | | 89 | | | 1,136 | | | 3 | | |||||||
Total other income (expense) | | | 46,604 | | | (4,038) | | | | (6,390) | | | 1,923 | | | 40,212 | | | (2,115) | |
NET LOSS BEFORE INCOME TAXES | | | (104,861) | | | (8,591) | | | | (27,665) | | | (4,534) | | | (132,526) | | | (13,125) | |
Income tax benefit (provision) | | | (394) | | | (27) | | |||||||||||||
Income tax provision | | | (369) | | | (427) | | | (763) | | | (454) | | |||||||
NET LOSS | | $ | (105,255) | | $ | (8,618) | | | $ | (28,034) | | $ | (4,961) | | $ | (133,289) | | $ | (13,579) | |
NET LOSS PER SHARE: | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | (0.80) | | $ | (0.26) | | | $ | (0.21) | | $ | (0.15) | | $ | (1.01) | | $ | (0.40) | |
Diluted | | $ | (0.80) | | $ | (0.26) | | | $ | (0.21) | | $ | (0.15) | | $ | (1.01) | | $ | (0.40) | |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | | | | | | | | | | | | | | |
Basic | | | 131,338 | | | 33,770 | | | | 131,449 | | | 33,909 | | | 131,394 | | | 33,840 | |
Diluted | | | 131,338 | | | 33,770 | | | | 131,449 | | | 33,909 | | | 131,394 | | | 33,840 | |
The accompanying notes are an integral part of these consolidated financial statements
54
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
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| | Three Months Ended | | | Six Months Ended | | ||||||||
| | March 31, | | | June 30, | | ||||||||
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| 2020 |
| 2019 |
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| 2020 |
| 2019 |
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| | (unaudited) | | | (unaudited) | | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | | | |
Net loss | | $ | (105,255) | | $ | (8,618) | | | $ | (133,289) | | $ | (13,579) | |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 12,854 | | | 7,556 | | | | 17,946 | | | 15,129 | |
Impairment of natural gas and oil properties | | | 145,878 | | | 483 | | |||||||
Impairment of oil and natural gas properties | | | 145,878 | | | 1,079 | | |||||||
Exploration expenditures - dry hole costs | | | 10,878 | | | — | | |||||||
Amortization of debt issuance costs | | | 177 | | | — | | | | 1,372 | | | — | |
Deferred income taxes | | | — | | | 424 | | | | — | | | 424 | |
Loss (gain) on sale of assets | | | (27) | | | 12 | | |||||||
Gain on sale of assets | | | (4,433) | | | (409) | | |||||||
Gain from investment in affiliates | | | (286) | | | (30) | | | | (113) | | | (457) | |
Stock-based compensation | | | 350 | | | 1,052 | | | | 616 | | | 1,637 | |
Unrealized loss (gain) on derivative instruments | | | (41,391) | | | 3,646 | | | | (21,192) | | | 2,078 | |
Changes in operating assets and liabilities: | | | | | | | | | | | | | | |
Decrease in accounts receivable & other receivables | | | 10,761 | | | 146 | | | | 13,614 | | | 1,530 | |
Decrease (increase) in prepaids | | | (245) | | | 835 | | | | (172) | | | 298 | |
Increase in inventory | | | (1) | | | — | | | | (1,560) | | | — | |
Decrease in accounts payable & advances from joint owners | | | (14,326) | | | (4,299) | | |||||||
Increase (decrease) in accounts payable & advances from joint owners | | | (17,132) | | | 8,592 | | |||||||
Decrease in other accrued liabilities | | | (1,951) | | | (826) | | | | (4,636) | | | (350) | |
Decrease (increase) in income taxes receivable, net | | | 241 | | | (424) | | | | 281 | | | (424) | |
Increase in income taxes payable, net | | | 192 | | | 27 | | |||||||
Increase in deposits and other | | | (7,219) | | | (123) | | |||||||
Net cash used in operating activities | | $ | (248) | | $ | (139) | | |||||||
Increase (decrease) in income taxes payable, net | | | 119 | | | (258) | | |||||||
Increase (decrease) in deposits and other | | | 36 | | | (392) | | |||||||
Net cash provided by operating activities | | $ | 8,213 | | $ | 14,898 | | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | |
Natural gas and oil exploration and development expenditures | | $ | (9,492) | | $ | (5,124) | | |||||||
Oil and natural gas exploration and development expenditures | | $ | (19,719) | | $ | (14,604) | | |||||||
Additions to furniture & equipment | | | — | | | (17) | | | | (77) | | | (17) | |
Sale of oil & gas properties | | | 5 | | | — | | | | 339 | | | — | |
Net cash used in investing activities | | $ | (9,487) | | $ | (5,141) | | | $ | (19,457) | | $ | (14,621) | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | |
Borrowings under credit facility | | $ | 37,000 | | $ | 37,025 | | | $ | 55,000 | | $ | 73,548 | |
Repayments under credit facility | | | (27,000) | | | (31,473) | | | | (48,600) | | | (73,548) | |
Net costs from equity offering | | | (47) | | | (86) | | |||||||
PPP loan | | | 3,369 | | | — | | |||||||
Net proceeds (costs) from equity offering | | | 435 | | | (41) | | |||||||
Purchase of treasury stock | | | (157) | | | (186) | | | | (180) | | | (236) | |
Net cash provided by financing activities | | $ | 9,796 | | $ | 5,280 | | |||||||
Net cash provided by (used in) financing activities | | $ | 10,024 | | $ | (277) | | |||||||
NET CHANGE IN CASH AND CASH EQUIVALENTS | | $ | 61 | | $ | — | | | $ | (1,220) | | $ | — | |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | | | 1,624 | | | — | | | | 1,624 | | | — | |
CASH AND CASH EQUIVALENTS, END OF PERIOD | | $ | 1,685 | | $ | — | | | $ | 404 | | $ | — | |
The accompanying notes are an integral part of these consolidated financial statements
65
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (DEFICIT)
For the threesix months ended March 31,June 30, 2020
(in thousands, except number of shares)
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| | Series C | | | | Additional | | | | | | | | Total | | | Series C | | | | Additional | | | | | | | | Total | | ||||||||||||||||
| | Preferred Stock | | Common Stock | | Paid-in | | Treasury | | Accumulated | | Shareholders’ | | | Preferred Stock | | Common Stock | | Paid-in | | Treasury | | Accumulated | | Shareholders’ | | ||||||||||||||||||||
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| Shares |
| Amount |
| Shares |
| Amount |
| Capital |
| Stock |
| Deficit |
| Equity |
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| Shares |
| Amount |
| Shares |
| Amount |
| Capital |
| Stock |
| Deficit |
| Equity (Deficit) |
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| | | | | | | (unaudited) | | | | | | | | (unaudited) | | ||||||||||||||||||||||||||||||
Balance at December 31, 2019 | | 2,700,000 | | $ | 108 | | 128,977,816 | | $ | 5,148 | | $ | 471,778 | | $ | (18) | | $ | (360,976) | | $ | 116,040 | | | 2,700,000 | | $ | 108 | | 128,977,816 | | $ | 5,148 | | $ | 471,778 | | $ | (18) | | $ | (360,976) | | $ | 116,040 | |
Equity offering costs | | — | | | — | | — | | | — | | | (47) | | | — | | | — | | | (47) | | | — | | | — | | — | | | — | | | (47) | | | — | | | — | | | (47) | |
Treasury shares at cost | | — | | | — | | (49,474) | | | — | | | — | | | (157) | | | — | | | (157) | | | — | | | — | | (49,474) | | | — | | | — | | | (157) | | | — | | | (157) | |
Restricted shares activity | | — | | | — | | 77,485 | | | 3 | | | (3) | | | — | | | — | | | — | | | — | | | — | | 77,485 | | | 3 | | | (3) | | | — | | | — | | | — | |
Stock-based compensation | | — | | | — | | — | | | — | | | 350 | | | — | | | — | | | 350 | | | — | | | — | | — | | | — | | | 350 | | | — | | | — | | | 350 | |
Net loss | | — | | | — | | — | | | — | | | — | | | — | | | (105,255) | | | (105,255) | | | — | | | — | | — | | | — | | | — | | | — | | | (105,255) | | | (105,255) | |
Balance at March 31, 2020 | | 2,700,000 | | $ | 108 | | 129,005,827 | | $ | 5,151 | | $ | 472,078 | | $ | (175) | | $ | (466,231) | | $ | 10,931 | | | 2,700,000 | | $ | 108 | | 129,005,827 | | $ | 5,151 | | $ | 472,078 | | $ | (175) | | $ | (466,231) | | $ | 10,931 | |
Equity offering - common stock | | — | | | — | | 155,029 | | | 6 | | | 477 | | | — | | | — | | | 483 | | |||||||||||||||||||||||
Conversion of preferred stock to common stock | | (2,700,000) | | | (108) | | 2,700,000 | | | 108 | | | — | | | — | | | — | | | — | | |||||||||||||||||||||||
Treasury shares at cost | | — | | | — | | (13,808) | | | — | | | — | | | (23) | | | — | | | (23) | | |||||||||||||||||||||||
Restricted shares activity | | — | | | — | | 149,709 | | | 6 | | | (6) | | | — | | | — | | | — | | |||||||||||||||||||||||
Stock-based compensation | | — | | | — | | — | | | — | | | 265 | | | — | | | — | | | 265 | | |||||||||||||||||||||||
Net loss | | — | | | — | | — | | | — | | | — | | | — | | | (28,034) | | | (28,034) | | |||||||||||||||||||||||
Balance at June 30, 2020 | | — | | $ | — | | 131,996,757 | | $ | 5,271 | | $ | 472,814 | | $ | (198) | | $ | (494,265) | | $ | (16,378) | |
The accompanying notes are an integral part of these consolidated financial statements
76
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
For the threesix months ended March 31,June 30, 2019
(in thousands, except number of shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Additional | | | | | | | | Total | | | | | Additional | | | | | | | | Total | | ||||||||||
| | Common Stock | | Paid-in | | Treasury | | Accumulated | | Shareholders’ | | | Common Stock | | Paid-in | | Treasury | | Accumulated | | Shareholders’ | | ||||||||||||||
|
| Shares |
| Amount |
| Capital |
| Stock |
| Deficit |
| Equity |
|
| Shares |
| Amount |
| Capital |
| Stock |
| Deficit |
| Equity (Deficit) |
| ||||||||||
| | (unaudited) | | | (unaudited) | | ||||||||||||||||||||||||||||||
Balance at December 31, 2018 | | 34,158,492 | | $ | 1,573 | | $ | 339,981 | | $ | (129,030) | | $ | (72,135) | | $ | 140,389 | | | 34,158,492 | | $ | 1,573 | | $ | 339,981 | | $ | (129,030) | | $ | (72,135) | | $ | 140,389 | |
Equity offering costs | | — | | | — | | | (86) | | | — | | | — | | | (86) | | | — | | | — | | | (86) | | | — | | | — | | | (86) | |
Treasury shares at cost | | (49,415) | | | — | | | — | | | (186) | | | — | | | (186) | | | (49,415) | | | — | | | — | | | (186) | | | — | | | (186) | |
Restricted shares activity | | 307,650 | | | 12 | | | (12) | | | — | | | — | | | — | | | 307,650 | | | 12 | | | (12) | | | — | | | — | | | — | |
Stock-based compensation | | — | | | — | | | 1,052 | | | — | | | — | | | 1,052 | | | — | | | — | | | 1,052 | | | — | | | — | | | 1,052 | |
Net loss | | — | | | — | | | — | | | — | | | (8,618) | | | (8,618) | | | — | | | — | | | — | | | — | | | (8,618) | | | (8,618) | |
Balance at March 31, 2019 | | 34,416,727 | | $ | 1,585 | | $ | 340,935 | | $ | (129,216) | | $ | (80,753) | | $ | 132,551 | | | 34,416,727 | | $ | 1,585 | | $ | 340,935 | | $ | (129,216) | | $ | (80,753) | | $ | 132,551 | |
Equity offering proceeds | | — | | | — | | | 45 | | | — | | | — | | | 45 | | ||||||||||||||||||
Treasury shares at cost | | (16,133) | | | — | | | — | | | (50) | | | — | | | (50) | | ||||||||||||||||||
Restricted shares activity | | 42,249 | | | 2 | | | (2) | | | — | | | — | | | — | | ||||||||||||||||||
Stock-based compensation | | — | | | — | | | 585 | | | — | | | — | | | 585 | | ||||||||||||||||||
Net loss | | — | | | — | | | — | | | — | | | (4,961) | | | (4,961) | | ||||||||||||||||||
Balance at June 30, 2019 | | 34,442,843 | | $ | 1,587 | | $ | 341,563 | | $ | (129,266) | | $ | (85,714) | | $ | 128,170 | |
The accompanying notes are an integral part of these consolidated financial statements
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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization and Business
Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based independent oil and natural gas company, with regional offices in Oklahoma City and Stillwater, Oklahoma. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas, Oklahoma, Louisiana and Wyoming properties and use that cash flow to explore, develop exploit and acquire oil and natural gas properties across the United States.
The following table lists the Company’s primary producing areas as of March 31,June 30, 2020:
Location |
| Formation |
Gulf of Mexico | | Offshore Louisiana - water depths less than 300 feet |
Mid-continent Region of Oklahoma | | Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork |
Southern Delaware Basin, Pecos County, Texas | | Wolfcamp A and B |
Madison and Grimes counties, Texas | | Woodbine / Upper Lewisville |
Zavala and Dimmit counties, Texas | | Buda / Eagle Ford / Georgetown |
San Augustine County, Texas | | Haynesville shale, Mid Bossier shale and James Lime |
Other Texas Gulf Coast | | Conventional and smaller unconventional formations |
Weston County, Wyoming | | Muddy Sandstone |
Sublette County, Wyoming | | Jonah Field (1) |
(1) | Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in the Company’s reported production results for all periods shown in this report. |
From the Company’s initial entry into the Southern Delaware Basin in 2016 and through mid-2019, the Company was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. In January 2020, the Company brought one West Texas well online but suspended further drilling in the area in response to the dramatic decline in oil prices during the quarter. As of March 31,June 30, 2020, the Company was producing from eighteen wells over its approximate 17,20016,200 gross operated (8,000(7,500 company net) acre position in this West Texas, area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.
During the fourth quarter of 2019, the Company closed on the acquisitions of certain producing assets and undeveloped acreage of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”), and established an additional core strategic area, located primarily located in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative, as production from these acquisitions represented 74%approximately 70% of the Company’s total net production for the first quarter of 2020.
During the fourth quarter of 2019, the Company also entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides the Company the right to acquire an interest in up tothree and six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline. The Iron Flea prospect was spud in late May 2020. Onmonths ended June 12, 2020, the target drilling depth was reached, and the prospect was determined unsuccessful. No further evaluation of that prospect is anticipated. As of March 31, 2020, the Company paid approximately $7.2 million in costs associated with the drilling of the Iron Flea prospect, of which $7.1 million was escrowed for the benefit of the turnkey drilling and is currently included in the Company’s consolidated balance sheet in “Deposits and other”. These costs will be expensed as exploration expense in the second quarter of30, 2020.
Impact of the COVID-19 Pandemic
A novel strain of the coronavirus ("COVID-19"(“COVID-19”) surfaced in late 2019 and has spread, and continues to spread, around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the
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battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. TheWhile there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which ishas negatively impactingimpacted the Company'sCompany’s results of operations and planned 2020 capital activities. Due to the extreme volatility in oil prices, the Company has suspended any further plans for onshore drilling in 2020.
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Management Services Agreement
On June 5, 2020, the Company announced the addition of a new corporate strategy that includes offering a property management service (or a “fee for service”) for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) (Nasdaq: MCEP), effective July 1, 2020, to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms of the warrants to be disclosed upon execution of the Warrant Agreement). Both the Company and Mid-Con and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56% of the common units in Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.
Authorized Shares of Common Stock and Conversion of Series C Contingent Convertible Preferred Stock
On June 10, 2020, the Company filed an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share (the “common stock”), of the Company from 200,000,000 shares to 400,000,000 shares. The Charter Amendment and the conversion of 2,700,000 shares of the Company’s Series C contingent convertible preferred stock, par value $0.04 per share (the “Series C contingent convertible preferred stock”), into 2,700,000 shares of the Company’s common stock were approved by the stockholders of the Company on June 8, 2020, at the Company’s 2020 Annual Meeting of Stockholders. The shares of Series C contingent convertible preferred stock were issued in a private placement completed concurrently with a private placement of common stock in December of 2019. Purchasers of the Series C contingent convertible preferred stock included John Goff, Wilkie Colyer and Farley Dakan, the Company’s current president.
Open Market Sale Agreement
On June 24, 2020, the Company entered into an Open Market Sale Agreement (the “Sale Agreement”) among the Company and Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the Sale Agreement, the Company may sell from time to time through the Sales Agent, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”). The Company intends to use the net proceeds from the offering, after deducting the Sales Agent’s commission and the Company’s offering expenses, to repay borrowings under its Credit Agreement (as defined below) and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the Sale Agreement, the Company sold 155,029 Shares during the three months ended June 30, 2020 for net proceeds of $0.5 million.
2. Summary of Significant Accounting Policies
The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2019 (“2019 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2019 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report.
Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature.
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The consolidated financial statements should be read in conjunction with the 2019 Form 10-K. These unaudited interim consolidated results of operations for the threesix months ended March 31,June 30, 2020 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2020.
The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The Company’s investment in Exaro, through its wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, production or productionreserves in those reported for the Company’s consolidated results of operations.
Oil and Gas Properties - Successful Efforts
The Company’s application of the successful efforts method of accounting for its oil and natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed, whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.9 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations. The evaluation of oil and natural gas and oil leasehold acquisition costs included in unproved properties requires management'smanagement’s judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
Impairment of Long-Lived Assets
Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by fieldregion basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, oil and natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to,
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estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value.
In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas in Marchuntil April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, as discussed above, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its current development plans for its proved, undeveloped locations. NoThe Company conducted an impairment of proved properties was recorded duringtest for the three months ended MarchJune 30, 2020, but no additional impairment was recorded. During the six months ended June 30, 2019, the company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2019.2018.
Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recorded a $2.6 million non-cash charge for unproved impairment expense during the threesix months ended March 31,June 30, 2020, all of which was recorded during the first quarter of 2020. The impairment primarily related to acquired leases in the Company’s Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which the Company has no current plans to develop
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as a result of the current commodity price environment. During the three months ended March 31, 2019, theThe Company recordedrecognized non-cash impairment expense of $0.5approximately $0.4 million and approximately $0.9 million for three and six months ended June 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases.
Net Loss Per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. The Company excluded 366,749506,325 shares or units, and 526,309414,383 shares or units of potentially dilutive securities during each of the three and six months ended March 31,June 30, 2020, respectively, as they were antidilutive. For the three and six months ended June 30, 2019, the company excluded 648,170 shares or units and 561,164 shares or units, respectively, of potentially dilutive securities, as they were antidilutive.
Subsidiary Guarantees
Contango Oil & Gas Company, as the parent company of certain subsidiaries (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. The registration statement has not yet been declared effective by the SEC. Any such debt securities would likely be guaranteed on a joint and several and full and unconditional basis by each of the Parent Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the current Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.
Revenue Recognition
Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product.
Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company
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receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice.
The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. The Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.
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Leases
The Company recognizes a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. The Company has modified procedures to its existing internal controls to review any new contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease at inception. The Company will continue to review all new or modified contracts on a quarterly basis for proper treatment. See Note 6 - "Leases"7 – “Leases” for additional information.
Recent Accounting Pronouncements
In June 2016, the FASB issued ASU 2016-13 – Financial Instruments – Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments – Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU 2019-05 (“ASU 2019-05”): Financial Instruments-Credit Losses (Topic 326) – Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 – Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.
In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. The amendments in this update are effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. ASU 2020-04 will be in effect through December 31, 2022. We are currently assessing the potential impact of ASU 2020-04 on our consolidated financial statements.
3. Dispositions
On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These properties were acquired in the Will Energy acquisition and were sold in exchange for the buyer’s assumption of the plugging and abandonment liabilities of these properties and revenue held in suspense. The Company recorded a gain of $4.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.
On April 1, 2020, the Company closed on the sale of certain non-producing properties located in its Central Oklahoma region. These properties were acquired in the White Star acquisition and were sold for approximately $0.5 million. The Company recorded a gain of $0.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.
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On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.
3.4. Fair Value Measurements
The Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. Fair value is 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 (exit price). A fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. 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, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of March 31,June 30, 2020. 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'sCompany’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.
Fair value information for financial assets and liabilities was as follows as of March 31,June 30, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total | | Fair Value Measurements Using | | | Total | | Fair Value Measurements Using | | ||||||||||||||||
|
| Carrying Value |
| Level 1 |
| Level 2 |
| Level 3 |
|
| Carrying Value |
| Level 1 |
| Level 2 |
| Level 3 |
| ||||||||
Derivatives | | | | | | | | | | | | | | | | | | | ||||||||
Commodity price contracts - assets | | $ | 40,454 | | $ | — | | $ | 40,454 | | $ | — | | | $ | 21,221 | | $ | — | | $ | 21,221 | | $ | — | |
Commodity price contracts - liabilities | | $ | (859) | | $ | — | | $ | (859) | | $ | — | | | $ | (1,825) | | $ | — | | $ | (1,825) | | $ | — | |
Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain“Gain (loss) on derivatives, net"net” in its consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in 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 45 – "Derivative Instruments"“Derivative Instruments” for additional discussion of derivatives.
As of March 31,June 30, 2020, the Company'sCompany’s derivative contracts were all with major institutions with investment grade credit ratings which are believed to have minimal credit risk, which primarily are lenders within the Company’s bank group. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.
Estimates of the fair value of financial instruments are 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, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company'sCompany’s Credit Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 910 – “Long-Term Debt” for further information.
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Impairments
The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by fieldregion basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital
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expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.
Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.
Asset Retirement Obligations
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company'sCompany’s exposure to price fluctuations and reduce the variability in the Company'sCompany’s cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts.
As of March 31,June 30, 2020, the Company’s oil and natural gas and oil derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.
It is the Company'sCompany’s policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit Agreement (as defined below) or under unsecured lines of credit with non-bank counterparties. See Note 910 – “Long-Term Debt” for further information regarding the Credit Agreement.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations.
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As of March 31,June 30, 2020, the following financial derivative instruments were in place (fair value in thousands):
| | | | | | | | | | | | | | | | | |
Commodity |
| Period |
| Derivative |
| Volume/Month |
| Price/Unit |
| Fair Value |
| ||||||
Oil | | July 2020 - Oct 2020 | | Collar | | 3,442 | Bbls | | $ | 52.00 | - | 65.70 | (1) | | $ | 176 | |
| | | | | | | | | | | | | | | | | |
Oil | | July 2020 - Dec 2020 | | Swap | | 15,000 | Bbls | | $ | 57.74 | (1) | | $ | 1,635 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | July 2020 | | Swap | | 5,500 | Bbls | | $ | 54.33 | (1) | | $ | 83 | | ||
Oil | | Aug 2020 - Oct 2020 | | Swap | | 2,500 | Bbls | | $ | 54.33 | (1) | | $ | 111 | | ||
Oil | | Nov 2020 - Dec 2020 | | Swap | | 3,500 | Bbls | | $ | 54.33 | (1) | | $ | 102 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | July 2020 | | Swap | | 37,500 | Bbls | | $ | 54.70 | (1) | | $ | 576 | | ||
Oil | | Aug 2020 - Dec 2020 | | Swap | | 35,000 | Bbls | | $ | 54.70 | (1) | | $ | 2,637 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | July 2020 | | Swap | | 37,500 | Bbls | | $ | 54.58 | (1) | | $ | 573 | | ||
Oil | | Aug 2020 - Dec 2020 | | Swap | | 35,000 | Bbls | | $ | 54.58 | (1) | | $ | 2,617 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | Jan 2021 - March 2021 | | Swap | | 19,000 | Bbls | | $ | 50.00 | (1) | | $ | 568 | | ||
Oil | | April 2021 - July 2021 | | Swap | | 12,000 | Bbls | | $ | 50.00 | (1) | | $ | 462 | | ||
Oil | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Bbls | | $ | 50.00 | (1) | | $ | 187 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | Jan 2021 - July 2021 | | Swap | | 62,000 | Bbls | | $ | 52.00 | (1) | | $ | 5,106 | | ||
Oil | | Aug 2021 - Sept 2021 | | Swap | | 55,000 | Bbls | | $ | 52.00 | (1) | | $ | 1,248 | | ||
Oil | | Oct 2021 - Dec 2021 | | Swap | | 64,000 | Bbls | | $ | 52.00 | (1) | | $ | 2,136 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Aug 2020 - Oct 2020 | | Swap | | 40,000 | Mmbtus | | $ | 2.532 | (2) | | $ | 87 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Nov 2020 - Dec 2020 | | Swap | | 375,000 | Mmbtus | | $ | 2.696 | (2) | | $ | 136 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | July 2020 | | Swap | | 400,000 | Mmbtus | | $ | 2.53 | (2) | | $ | 828 | | ||
Natural Gas | | Aug 2020 - Dec 2020 | | Swap | | 350,000 | Mmbtus | | $ | 2.53 | (2) | | $ | 768 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | July 2020 | | Swap | | 400,000 | Mmbtus | | $ | 2.532 | (2) | | $ | 415 | | ||
Natural Gas | | Aug 2020 - Dec 2020 | | Swap | | 350,000 | Mmbtus | | $ | 2.532 | (2) | | $ | 770 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 185,000 | Mmbtus | | $ | 2.505 | (2) | | $ | (176) | | ||
Natural Gas | | April 2021 - July 2021 | | Swap | | 120,000 | Mmbtus | | $ | 2.505 | (2) | | $ | 11 | | ||
Natural Gas | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Mmbtus | | $ | 2.505 | (2) | | $ | (1) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 185,000 | Mmbtus | | $ | 2.508 | (2) | | $ | (174) | | ||
Natural Gas | | April 2021 - July 2021 | | Swap | | 120,000 | Mmbtus | | $ | 2.508 | (2) | | $ | 13 | | ||
Natural Gas | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Mmbtus | | $ | 2.508 | (2) | | $ | (1) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 650,000 | Mmbtus | | $ | 2.508 | (1) | | $ | (612) | | ||
Natural Gas | | April 2021 - Oct 2021 | | Swap | | 400,000 | Mmbtus | | $ | 2.508 | (1) | | $ | 4 | | ||
Natural Gas | | Nov 2021 - Dec 2021 | | Swap | | 580,000 | Mmbtus | | $ | 2.508 | (2) | | $ | (178) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | April 2021 - Nov 2021 | | Swap | | 70,000 | Mmbtus | | $ | 2.36 | (2) | | $ | (92) | | ||
Natural Gas | | Dec 2021 | | Swap | | 350,000 | Mmbtus | | $ | 2.36 | (2) | | $ | (130) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2022 - March 2022 | | Swap | | 780,000 | Mmbtus | | $ | 2.542 | (2) | | $ | (489) | | ||
| | | | | | | | | | | | | | | | | |
| | | | Total net fair value of derivative instruments | | | $ | 19,396 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Commodity |
| Period |
| Derivative |
| Volume/Month |
| Price/Unit |
| Fair Value |
| ||||||
Natural Gas | | April 2020 - July 2020 | | Swap | | 400,000 | Mmbtus | | $ | 2.532 | (1) | | $ | 1,271 | | ||
Natural Gas | | Aug 2020 - Oct 2020 | | Swap | | 40,000 | Mmbtus | | $ | 2.532 | (1) | | $ | 62 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Nov 2020 - Dec 2020 | | Swap | | 375,000 | Mmbtus | | $ | 2.696 | (1) | | $ | 180 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | April 2020 - July 2020 | | Swap | | 400,000 | Mmbtus | | $ | 2.53 | (1) | | $ | 1,268 | | ||
Natural Gas | | Aug 2020 - Dec 2020 | | Swap | | 350,000 | Mmbtus | | $ | 2.53 | (1) | | $ | 587 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | April 2020 - July 2020 | | Swap | | 400,000 | Mmbtus | | $ | 2.532 | (1) | | $ | 1,271 | | ||
Natural Gas | | Aug 2020 - Dec 2020 | | Swap | | 350,000 | Mmbtus | | $ | 2.532 | (1) | | $ | 591 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 185,000 | Mmbtus | | $ | 2.505 | (1) | | $ | (98) | | ||
Natural Gas | | April 2021 - July 2021 | | Swap | | 120,000 | Mmbtus | | $ | 2.505 | (1) | | $ | 66 | | ||
Natural Gas | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Mmbtus | | $ | 2.505 | (1) | | $ | 2 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 185,000 | Mmbtus | | $ | 2.508 | (1) | | $ | (96) | | ||
Natural Gas | | April 2021 - July 2021 | | Swap | | 120,000 | Mmbtus | | $ | 2.508 | (1) | | $ | 67 | | ||
Natural Gas | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Mmbtus | | $ | 2.508 | (1) | | $ | 2 | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2021 - March 2021 | | Swap | | 650,000 | Mmbtus | | $ | 2.508 | (1) | | $ | (340) | | ||
Natural Gas | | April 2021 - Oct 2021 | | Swap | | 400,000 | Mmbtus | | $ | 2.508 | (1) | | $ | 348 | | ||
Natural Gas | | Nov 2021 - Dec 2021 | | Swap | | 580,000 | Mmbtus | | $ | 2.508 | (1) | | $ | (36) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | April 2021 - Nov 2021 | | Swap | | 70,000 | Mmbtus | | $ | 2.36 | (1) | | $ | (87) | | ||
Natural Gas | | Dec 2021 | | Swap | | 350,000 | Mmbtus | | $ | 2.36 | (1) | | $ | (21) | | ||
| | | | | | | | | | | | | | | | | |
Natural Gas | | Jan 2022 - March 2022 | | Swap | | 780,000 | Mmbtus | | $ | 2.542 | (1) | | $ | (216) | | ||
| | | | | | | | | | | | | | | | | |
Oil | | April 2020 - Oct 2020 | | Collar | | 3,442 | Bbls | | $ | 52.00 | - | 65.70 | (2) | | $ | 559 | |
| | | | | | | | | | | | | | | | | |
Oil | | April 2020 - June 2020 | | Swap | | 22,000 | Bbls | | $ | 57.74 | (2) | | $ | 2,139 | | ||
Oil | | July 2020 - Dec 2020 | | Swap | | 15,000 | Bbls | | $ | 57.74 | (2) | | $ | 2,257 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | April 2020 - June 2020 | | Swap | | 2,500 | Bbls | | $ | 54.33 | (2) | | $ | 218 | | ||
Oil | | July 2020 | | Swap | | 5,500 | Bbls | | $ | 54.33 | (2) | | $ | 132 | | ||
Oil | | Aug 2020 - Oct 2020 | | Swap | | 2,500 | Bbls | | $ | 54.33 | (2) | | $ | 164 | | ||
Oil | | Nov 2020 - Dec 2020 | | Swap | | 3,500 | Bbls | | $ | 54.33 | (2) | | $ | 141 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | April 2020 - July 2020 | | Swap | | 37,500 | Bbls | | $ | 54.70 | (2) | | $ | 4,217 | | ||
Oil | | Aug 2020 - Dec 2020 | | Swap | | 35,000 | Bbls | | $ | 54.70 | (2) | | $ | 3,780 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | April 2020 - July 2020 | | Swap | | 37,500 | Bbls | | $ | 54.58 | (2) | | $ | 4,199 | | ||
Oil | | Aug 2020 - Dec 2020 | | Swap | | 35,000 | Bbls | | $ | 54.58 | (2) | | $ | 3,759 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | Jan 2021 - March 2021 | | Swap | | 19,000 | Bbls | | $ | 50.00 | (2) | | $ | 837 | | ||
Oil | | April 2021 - July 2021 | | Swap | | 12,000 | Bbls | | $ | 50.00 | (2) | | $ | 647 | | ||
Oil | | Aug 2021 - Sept 2021 | | Swap | | 10,000 | Bbls | | $ | 50.00 | (2) | | $ | 252 | | ||
| | | | | | | | | | | | | | | | | |
Oil | | Jan 2021 - July 2021 | | Swap | | 62,000 | Bbls | | $ | 52.00 | (2) | | $ | 6,936 | | ||
Oil | | Aug 2021 - Sept 2021 | | Swap | | 55,000 | Bbls | | $ | 52.00 | (2) | | $ | 1,610 | | ||
Oil | | Oct 2021 - Dec 2021 | | Swap | | 64,000 | Bbls | | $ | 52.00 | (2) | | $ | 2,682 | | ||
| | | | | | | | | | | | | | | | | |
| | | | Total net fair value of derivative instruments | | | $ | 39,350 | |
(1) Based on West Texas Intermediate oil prices.
(2) Based on Henry Hub NYMEX natural gas prices.
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(1) Based on Henry Hub NYMEX natural gas prices.
(2) Based on West Texas Intermediate oil prices.
In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of oil per month for April 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in an asset position of $0.2 millionzero as of March 31,June 30, 2020.
The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31,June 30, 2020 (in thousands):
| | | | | | | | | | | | | | | | | | | | |
|
| Gross |
| Netting (1) |
| Total |
|
| Gross |
| Netting (1) |
| Total |
| ||||||
Assets | | $ | 40,454 | | $ | — | | $ | 40,454 | | | $ | 21,221 | | $ | — | | $ | 21,221 | |
Liabilities | | $ | (859) | | $ | — | | $ | (859) | | | $ | (1,825) | | $ | — | | $ | (1,825) | |
(1) Represents counterparty netting under agreements governing such derivatives.
The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2019 (in thousands):
| | | | | | | | | | |
|
| Gross |
| Netting (1) |
| Total | | |||
Assets | | $ | 4,176 | | $ | — | | $ | 4,176 | |
Liabilities | | $ | (5,971) | | $ | — | | $ | (5,971) | |
(1) Represents counterparty netting under agreements governing such derivatives.
The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and six months ended March 31,June 30, 2020 and 2019 (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | Three Months Ended June 30, | | Six Months Ended June 30, | | ||||||||||||
|
| 2020 |
| 2019 |
|
| 2020 |
| 2019 |
| 2020 |
| 2019 |
| ||||||
Oil contracts | | $ | 2,797 | | $ | 655 | | | $ | 8,461 | | $ | 286 | | $ | 11,258 | | $ | 941 | |
Natural gas contracts | | | 2,511 | | | 113 | | | | 2,933 | | | 211 | | | 5,445 | | | 324 | |
Realized gain | | $ | 5,308 | | $ | 768 | | | $ | 11,394 | | $ | 497 | | $ | 16,703 | | $ | 1,265 | |
| | | | | | | | | | | | | | | | | | | | |
Oil contracts | | $ | 40,727 | | $ | (3,443) | | | $ | (16,557) | | $ | 365 | | $ | 24,170 | | $ | (3,077) | |
Natural gas contracts | | | 664 | | | (203) | | | | (3,641) | | | 1,203 | | | (2,978) | | | 999 | |
Unrealized gain (loss) | | $ | 41,391 | | $ | (3,646) | | | $ | (20,198) | | $ | 1,568 | | $ | 21,192 | | $ | (2,078) | |
Gain (loss) on derivatives, net | | $ | 46,699 | | $ | (2,878) | | | $ | (8,804) | | $ | 2,065 | | $ | 37,895 | | $ | (813) | |
5.6. Stock-Based Compensation
Amended and Restated 2009 Incentive Compensation Plan
On June 8, 2020, the stockholders of the Company approved the third amendment to the Amended and Restated 2009 Incentive Compensation Plan (as amended, the “Plan”) in the form of an amendment and restatement of the Plan that, among other things, increases the number of shares of the Company’s common stock authorized for issuance pursuant to the Plan by 9,000,000 shares and increases the maximum aggregate number of shares of common stock that may be granted to any individual during any calendar year from 250,000 to 1,000,000. The Plan allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award.
Restricted Stock
During the six months ended June 30, 2020, the Company granted 152,248 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2020, was $2.42 per share, with a total fair value of approximately $0.4 million and no adjustment for an estimated weighted average forfeiture rate. There were no grants or2,539 forfeitures of restricted stock during the threesix months ended March 31,June 30, 2020. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2020 was approximately $10 thousand. In July 2020, the Company granted 1,037,969 shares of restricted common stock, which vest ratably over three years, to employees as part of their overall compensation package. The weighted average fair value of the restricted shares granted in July 2020, was $2.24 per share,
16
with a total fair value of approximately $2.3 million and no adjustment for an estimated weighted average forfeiture rate. The Company recognized approximately $0.2$0.4 million in restricted stock compensation expense during the threesix months ended March 31,June 30, 2020 related to restricted stock previously granted to its officers, employees and directors. As of March 31,June 30, 2020, an additional $0.6$0.8 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.71.3 years. Approximately 1.310.1 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of March 31,June 30, 2020, assuming PSUs (as defined below) are settled at 100% of target.
During the threesix months ended March 31,June 30, 2019, the Company granted 307,650 shares of restricted common stock, which vest ratably over three years, to employees and executive officers as part of their overall compensation package. Additionally, during the six months ended June 30, 2019, the Company granted 80,410 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the threesix months ended March 31,June 30, 2019, was $3.20$2.91 per share, with a total fair value of approximately $1.0$1.1 million and no adjustment for an estimated weighted average forfeiture rate. ThereDuring the six months ended June 30, 2019, 38,161 restricted shares were no forfeituresforfeited by former employees. The aggregate intrinsic value of restricted stockshares forfeited during the threesix months ended March 31, 2019.June 30, 2019 was approximately $0.2 million. The Company recognized
16
approximately $1.0$1.4 million in restricted stock compensation expense during the threesix months ended March 31,June 30, 2019 related to restricted stock granted to its officers, employees and directors.
Performance Stock Units
Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company'sCompany’s common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the targeted number of PSUs stated in the agreement, contingent upon the achievement of certain share price appreciation targets as compared to a peer group index.index over a three year performance period. The PSUs vest and settlement is determined after aat the end of the three year period.performance period, with the final number of shares to be granted determined at that time, based on the Company’s share performance during the period compared to the average performance of the peer group.
Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company'sCompany’s common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.
There were no grants or forfeitures of PSUs during the threesix months ended MarchJune 30, 2020. In July 2020, Company granted 2,608,640 PSUs to its executive officers and certain employees as part of their overall compensation package. The performance period will be measured between January 1, 2020 and December 31, 2020.2022. These granted PSUs were valued at a weighted average fair value of $4.90 per unit. In January 2020, 77,485 shares of the PSUs granted in 2017 vested, of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. No PSUs were forfeited during the six months ended June 30, 2020. The Company recognized approximately $0.1$0.2 million in stock compensation expense related to PSUs during the threesix months ended March 31,June 30, 2020. As of March 31,June 30, 2020, an additional $0.6$0.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.61.4 years.
During the threesix months ended March 31,June 30, 2019, the Company granted 117,105 PSUs to executive officers and certain employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the threesix months ended March 31,June 30, 2019, 49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $14 thousand$0.3 million in stock compensation expense related to PSUs during the threesix months ended March 31, 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures.June 30, 2019.
17
Stock Options
Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the threesix months ended March 31,June 30, 2020 and 2019, there was no excess tax benefit recognized.
Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the threesix months ended March 31,June 30, 2020 or 2019.
During the threesix months ended March 31,June 30, 2020, no stock options were exercised and stock options for 329411 shares were forfeited by former employees. During the threesix months ended March 31,June 30, 2019, no stock options were exercised and stock options for 12,052 shares were forfeited by former employees.
During the threesix months ended March 31,June 30, 2020, the Company entered into a new compressor contractcontracts with lease terms of twelve months or more, which qualifiesqualify as an operating lease.leases. The Company also entered into new contracts for vehicles and office equipment and a vehicle with lease terms of twelve months or more, which qualify as finance leases. As of March 31,June 30, 2020, the Company’s operating leases were for compressors and office space at its two corporate offices and three field offices, while the Company’s finance leases were for vehicles and office equipment.
17
The Company also has compressor contracts which are on a month-to-month basis, and while it is probable the contractcontracts will be renewed on a monthly basis, the compressors can be easily substituted or cancelled by either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term.
The following table summarizes the balance sheet information related to the Company’s leases as of March 31,June 30, 2020 and December 31, 2019 (in thousands):
| | | | | | | | | | | | |
| March 31, 2020 |
| December 31, 2019 | | June 30, 2020 |
| December 31, 2019 | | ||||
Operating lease right of use asset (1) | $ | 3,772 | | $ | 4,316 | | $ | 3,993 | | $ | 4,316 | |
| | | | | | | | | | | | |
Operating lease liability - current (2) | $ | (2,556) | | $ | (2,597) | | $ | (2,897) | | $ | (2,597) | |
Operating lease liability - long-term (3) | | (1,202) | | | (1,738) | | | (1,045) | | | (1,738) | |
Total operating lease liability | $ | (3,758) | | $ | (4,335) | | $ | (3,942) | | $ | (4,335) | |
| | | | | | | | | | | ||
Financing lease right of use asset (1) | $ | 1,533 | | $ | 1,569 | | $ | 1,698 | | $ | 1,569 | |
| | | | | | | | | | | | |
Financing lease liability - current (2) | $ | (550) | | $ | (524) | | $ | (605) | | $ | (524) | |
Financing lease liability - long-term (3) | | (994) | | | (1,051) | | | (1,111) | | | (1,051) | |
Total financing lease liability | $ | (1,544) | | $ | (1,575) | | $ | (1,716) | | $ | (1,575) | |
(1) | Included in “Right-of-use lease assets” on the consolidated balance sheet. |
(2) | Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet. |
(3) | Included in “Lease liabilities” on the consolidated balance sheet. |
The Company'sCompany’s leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating and financing lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment. For leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.
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The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of March 31,June 30, 2020 and December 31, 2019:
| | | | | | | | | | | ||
| | March 31, 2020 | | December 31, 2019 | | | June 30, 2020 | | December 31, 2019 | | ||
Weighted Average Remaining Lease Terms (in years): | | | | | | | | | | | ||
Operating leases | | 1.93 | | 2.16 | | | 1.81 | | 2.16 | | ||
Financing leases | | 3.00 | | 3.14 | | | 3.14 | | 3.14 | | ||
| | | | | | | | | | | ||
Weighted Average Discount Rate: | | | | | | | | | | | ||
Operating leases | | 6.04% | | 6.04% | | | 5.75% | | 6.04% | | ||
Financing leases | | 6.21% | | 6.24% | | | 5.90% | | 6.24% | |
Maturities for the Company’s lease liabilities on the consolidated balance sheet as of March 31,June 30, 2020, were as follows (in thousands):
| | | | | | | | | | | | | | |
| March 31, 2020 | | June 30, 2020 | | ||||||||||
| Operating Leases | | | Financing Leases | | Operating Leases | | | Financing Leases | | ||||
2020 (remaining after March 31, 2020) | $ | 2,710 | | | $ | 631 | | |||||||
2020 (remaining after June 30, 2020) | $ | 3,040 | | | $ | 690 | | |||||||
2021 | | 825 | | | | 527 | | | 702 | | | | 552 | |
2022 | | 172 | | | | 370 | | | 168 | | | | 475 | |
2023 | | 170 | | | | 150 | | | 171 | | | | 156 | |
2024 | | 115 | | | | 19 | | | 72 | | | | 7 | |
Total future minimum lease payments | | 3,992 | | | | 1,697 | | | 4,153 | | | | 1,880 | |
Less: imputed interest | | (234) | | | | (153) | | | (211) | | | | (164) | |
Present value of lease liabilities | $ | 3,758 | | | $ | 1,544 | | $ | 3,942 | | | $ | 1,716 | |
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The following table summarizes expenses related to the Company’s leases for the three months ended March 31,June 30, 2020 and 2019 (in thousands):
| | | | | | | | | | | | | | |
| Three Months Ended March 31, 2020 | | | Three Months Ended March 31, 2019 | | Three Months Ended June 30, 2020 | | | Three Months Ended June 30, 2019 | | ||||
Operating lease cost (1) (2) | $ | 687 | | | $ | 371 | | $ | 743 | | | $ | 100 | |
Financing lease cost - amortization of right-of-use assets | | 135 | | | | - | | | 155 | | | | - | |
Financing lease cost - interest on lease liabilities | | 24 | | | | - | | | 27 | | | | - | |
Administrative lease cost (3) | | 19 | | | | 19 | | | 19 | | | | 18 | |
Short-term lease cost (1) (4) | | 437 | | | | 510 | | | 615 | | | | 2,068 | |
Total lease cost | $ | 1,302 | | | $ | 900 | | $ | 1,559 | | | $ | 2,186 | |
(1) | This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. |
(2) | Costs related to office leases and compressors with lease terms of twelve months or more. |
(3) | Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. |
(4) | Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year. |
The following table summarizes expenses related to the Company’s leases for the six months ended June 30, 2020 and 2019 (in thousands):
| | | | | | | |
| Six Months Ended June 30, 2020 | | | Six Months Ended June 30, 2019 | | ||
Operating lease cost (1) (2) | $ | 1,430 | | | $ | 471 | |
Financing lease cost - amortization of right-of-use assets | | 284 | | | | - | |
Financing lease cost - interest on lease liabilities | | 52 | | | | - | |
Administrative lease cost (3) | | 38 | | | | 37 | |
Short-term lease cost (1) (4) | | 1,053 | | | | 2,578 | |
Total lease cost | $ | 2,857 | | | $ | 3,086 | |
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(1) | This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. |
(2) | Costs related to office leases and compressors with lease terms of twelve months or more. |
(3) | Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. |
(4) | Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year. |
During the threesix months ended March 31,June 30, 2020, there were $0.7$1.5 million and $0.2$0.3 million in cash payments related to operating leases and financing leases, respectively. During the threesix months ended March 31,June 30, 2019, there were no$0.1 million in cash payments related to operating leases orleases. No cash payments were made for the financing leases asduring the operating lease payments did not begin until the second quarter of 2019, and there were no financing leases as of March 31,six months ended June 30, 2019.
7.8. Other Financial Information
The following table provides additional detail for accounts receivable, prepaid expenses, and other,inventory and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):
| | | | | | | | | | | | | | |
|
| March 31, 2020 |
| December 31, 2019 |
|
| June 30, 2020 |
| December 31, 2019 |
| ||||
Accounts receivable: | | | | | | | | | | | | | | |
Trade receivables (1) | | $ | 12,003 | | $ | 21,110 | | | $ | 9,527 | | $ | 21,110 | |
Receivable for Alta Resources distribution | | | 1,712 | | | 1,712 | | | | 1,712 | | | 1,712 | |
Joint interest billings | | | 12,252 | | | 13,104 | | | | 12,220 | | | 13,104 | |
Income taxes receivable | | | 268 | | | 509 | | | | 268 | | | 509 | |
Other receivables | | | 3,324 | | | 4,126 | | | | 2,939 | | | 4,126 | |
Allowance for doubtful accounts | | | (994) | | | (994) | | | | (994) | | | (994) | |
Total accounts receivable | | $ | 28,565 | | $ | 39,567 | | | $ | 25,672 | | $ | 39,567 | |
| | | | | | | | | | | | | | |
Prepaid expenses and other: | | | | | | | | |||||||
Prepaid expenses: | | | | | | | | |||||||
Prepaid insurance | | $ | 233 | | $ | 683 | | | $ | 335 | | $ | 683 | |
Other (2) | | | 1,203 | | | 508 | | | | 1,028 | | | 508 | |
Total prepaid expenses and other | | $ | 1,436 | | $ | 1,191 | | |||||||
Total prepaid expenses | | $ | 1,363 | | $ | 1,191 | | |||||||
| | | | | | | | |||||||
Inventory: | | | | | | | | |||||||
Oil storage (3) | | $ | 947 | | $ | — | | |||||||
Materials and supplies | | | 763 | | | 186 | | |||||||
Total inventory | | $ | 1,710 | | $ | 186 | | |||||||
| | | | | | | | | | | | | | |
Accounts payable and accrued liabilities: | | | | | | | | | | | | | | |
Royalties and revenue payable | | $ | 46,765 | | $ | 49,644 | | | $ | 39,950 | | $ | 49,644 | |
Advances from partners (3) | | | 120 | | | 6,733 | | |||||||
Accrued exploration and development (3) | | | 2,334 | | | 8,210 | | |||||||
Advances from partners (4) | | | 868 | | | 6,733 | | |||||||
Accrued exploration and development (4) | | | 1,463 | | | 8,210 | | |||||||
Trade payables | | | 10,993 | | | 14,086 | | | | 15,192 | | | 14,086 | |
Accrued general and administrative expenses (4) | | | 11,589 | | | 12,037 | | |||||||
Accrued general and administrative expenses (5) | | | 5,739 | | | 12,037 | | |||||||
Accrued operating expenses | | | 5,362 | | | 5,794 | | | | 8,881 | | | 5,794 | |
Accrued short term leases | | | 3,106 | | | 3,120 | | |||||||
Accrued operating and finance leases | | | 3,502 | | | 3,120 | | |||||||
Other accounts payable and accrued liabilities | | | 3,473 | | | 4,969 | | | | 1,548 | | | 4,969 | |
Total accounts payable and accrued liabilities | | $ | 83,742 | | $ | 104,593 | | | $ | 77,143 | | $ | 104,593 | |
(1) | Decrease in 2020 primarily due to lower receivables from oil sales as a result of the dramatic decline in oil prices |
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(2) | Other prepaids primarily includes software licenses and additional licenses purchased |
(3) | Includes approximately 50,000 Bbls of oil (net to the Company) produced during the three months ended June 30, 2020, held as inventory in the Company’s Central Oklahoma region and sold in the third quarter of 2020. |
(4) | Decrease in 2020 due to a decrease in drilling and completion |
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Includes accruals for legal judgments, of which $6.3 million was paid in April 2020.See Note |
Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the threesix months ended March 31,June 30, 2020 and 2019 (in thousands):
| | | | | | | | | | | | |
| | Three Months Ended March 31, | | | Six Months Ended June 30, | | ||||||
| | 2020 |
| | 2019 |
| | 2020 |
| | 2019 |
|
Cash payments: | | | | | | | | | | | | |
Interest payments | $ | 1,267 | | $ | 1,046 | | $ | 2,006 | | $ | 2,157 | |
Income tax payments (refunds) | $ | (7) | | $ | 40 | | ||||||
Income tax payments | $ | 83 | | $ | 805 | | ||||||
Non-cash investing activities in the consolidated statements of cash flows: | | | | | | | | | | | | |
Decrease in accrued capital expenditures | $ | (4,676) | | $ | (2,220) | | ||||||
Increase (decrease) in accrued capital expenditures | $ | (7,095) | | $ | 475 | |
8.9. Investment in Exaro Energy III LLC
The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at March 31,June 30, 2020 was approximately $7.1$6.9 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results or production in those reported for the Company’s consolidated results.
The Company’s share in Exaro’s results of operations recognized for each of the three months ended March 31,June 30, 2020 and 2019 was a loss of $0.2 million, net of no tax expense and a gain of $0.4 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the six months ended June 30, 2020 and 2019 was a gain of $0.3$0.1 million, net of no tax expense.expense, and a gain of $0.7 million, net of no tax expense, respectively.
9.10. Long-Term Debt
Credit Agreement
On September 17, 2019, the Company entered into its new revolving credit agreement with JPMorgan Chase Bank and other lenders (the(as amended, the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the acquisitions of certain producing assets and undeveloped acreage from Will Energy and White Star, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base was $145 million as of March 31, 2020. The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1st and November 1st of each year. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million pursuant to the regularly scheduled redetermination process. The Second Amendment also provides for, among other things, further $10 million automatic reductions in the borrowing base on each of June 30, 2020 and September 30, 2020. As a result, the borrowing base was $85 million as of June 30, 2020. The borrowing base may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The Credit Agreement matures on September 17, 2024.
The Company initially incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, which is to be amortized over the five year term of the Credit Agreement. No fees were paid for the Second Amendment. However, during the three months ended June 30, 2020 the Company expensed $1.0 million of the fees discussed above, which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. As of March 31,June 30, 2020, the remaining amortizable balance of these fees was $3.1$1.9 million, which will be amortized through September 17, 2024.
As of March 31,June 30, 2020, the Company had approximately $82.8$79.1 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of December 31, 2019, the Company had approximately $72.8 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of March 31,June 30, 2020, borrowing availability under the Credit Agreement was $60.4$4.0 million.
Total interest expense under the Company’s current and previous credit agreements, including commitment fees and the additional $1.0 million in expensed loan fees discussed above, for the three and six months ended March 31,June 30, 2020 and March 31, 2019 was approximately $1.2 million and $1.1 million, respectively. The weighted average interest rates in effect at March 31, 2020 and December 31, 2019 were 4.2% and 4.3%, respectively.
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was approximately $2.2 million and $3.4 million, respectively. Total interest expense under the credit facility, including commitment fees, for the three and six months ended June 30, 2019 was approximately $1.1 million and $2.2 million, respectively.
The weighted average interest rates in effect at June 30, 2020 and December 31, 2019 were 4.0% and 4.3%, respectively.
The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement.
The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment, also contains, among other things, provides for an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, providesand includes provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of March 31,June 30, 2020, the Company was in compliance with all of its covenants under the Credit Agreement.
Paycheck Protection Program Loan
On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A and is included in “Long Term Debt” on the Company’s consolidated balance sheet.
The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.
Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: (1) the eight-week period beginning on the funding date; or (2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. The Company intends to use the PPP Loan amount for qualifying expenses and expects to apply for forgiveness of all or part of the PPP Loan in accordance with the terms of the CARES Act and related guidance. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.
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10.11. Income Taxes
The Company’s income tax provision for continuing operations consists of the following (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | Three Months Ended June 30, | | Six Months Ended June 30, | | ||||||||||||
|
| 2020 |
| 2019 | |
| 2020 |
| 2019 | | 2020 | | 2019 | | ||||||
Current tax provision: | | | | | | | | | | | | | | | ||||||
Federal | | $ | 275 | | $ | — | | | $ | — | | $ | — | | $ | 275 | | $ | — | |
State | | | 119 | | | 27 | | | | (7) | | | 427 | | | 112 | | | 454 | |
Total | | $ | 394 | | $ | 27 | | | $ | (7) | | $ | 427 | | $ | 387 | | $ | 454 | |
Deferred tax provision: | | | | | | | | | | | | | | |||||||
Federal | | $ | — | | $ | — | | $ | — | | $ | — | | |||||||
State | | | 376 | | | — | | | 376 | | | — | | |||||||
Total | | $ | 376 | | $ | — | | $ | 376 | | $ | — | | |||||||
Total tax provision: | | | | | | | | | | | | | | | | | | | | |
Federal | | $ | 275 | | $ | — | | | $ | — | | $ | — | | $ | 275 | | $ | — | |
State | | | 119 | | | 27 | | | | 369 | | | 427 | | | 488 | | | 454 | |
Total income tax provision: | | $ | 394 | | $ | 27 | | | $ | 369 | | $ | 427 | | $ | 763 | | $ | 454 | |
The Federal income tax expense results from an adjustment in the previous period of the credit for previously paid Alternative Minimum Tax which(“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable byrefundable. The first half of the Tax Cutscredit was refunded when the Company filed its 2018 federal income tax return, and Jobs Act of 2017 (“TCJA”). Thethe second half of the credit originally becamewill be refundable withwhen the filedCompany files its tax return for the tax year ended December 31, 2019. The Coronavirus Aid, Relief, and Economic SecurityCARES Act (“CARES Act”), signed into law on March 27, 2020, modified this treatment, nowthe timing of these refunds, allowing the Company to request an expedited refund of $0.9$0.3 million whichthis quarter. This amount was previously accounted for as an income tax benefit when the TCJAcorporate AMT was enacted.repealed. State income tax expense relates to expected income taxes for the quarter and the six months which are expected to be owed to the states of Louisiana and Oklahoma imposed on propertiesresulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes.
Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). In addition, the Company used relief granted by the Oklahoma Tax Commission and the Louisiana Tax Commission to extend the due date for the first quarter estimated income tax payments to the states of Oklahoma and Louisiana to July 15, 2020. No Federal estimated tax payments for 2020 are expected. The Company does not expect to benefit from any other income tax-related provisions of the CARES Act.
In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and, therefore, adjusted valuation allowances for federal and state purposes (with the exception of Oklahoma) to $126.3$132.0 million and $1.0$1.6 million, respectively, as of March 31,June 30, 2020. Oklahoma deferred tax expense of $0.4 million was recognized during the quarter ended June 30, 2020. No Oklahoma valuation allowance has been recorded as of June 30, 2020. The $22.1$28.5 million net increase from the net valuation allowance recorded at December 31, 2019, like other items in the
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company’s Company’s accounting for income taxes during the current quarter, was determined using a specific March 31,June 30, 2020 cut-off date as an accurate estimate of 2020 pre-tax income or income tax expense cannot be reliably made at this time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.
As of March 31,June 30, 2020, the Company had federal net operating loss (“NOL”) carryforwards of approximately $383.9$398.7 million and state NOLs of $20.4$32.7 million. The Federal NOL carryforwards occurred due to the merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) and subsequent taxable losses during the years 2014 through 2019 due to lower commodity prices
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and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and gas properties.
Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. The CARES Act temporarily suspends the Section 172 limitation for NOLs arising in tax years beginning in 2018, 2019 and 2020 and also allows NOLs originating in these years to be carried back five years; however, the Company does not expect to receive any federal tax refunds from the temporary suspension of the Section 172 limitation because the Company tax losses in each of the carryback years.
The Company experienced two separate Section 382 Ownership Changes in connection with two of its equity offerings occurring in 2018 and 2019, respectively (the “Ownership Changes”). Market conditions at the time of the 2019 Ownership Change had diminished from the time of the 2018 Ownership Change, thus subjecting virtually all of the Company’s tax attributes to an annual limitation of $0.7 million a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future. ForDuring the quarter ended March 31,June 30, 2020, the Company did not have anyhad no activity which resultedresulting in an additional Section 382 Ownership Change.
The CARES Act temporarily suspends the Section 172 limitation for NOLs arising in tax years beginning in 2018, 2019 and 2020 and also allows NOLs originating in these years to be carried back five years; however, the Company does not expect to receive any federal tax refunds from the temporary suspension of the Section 172 limitation because the Company incurred tax losses in each of the carryback years.
11.12. Commitments and Contingencies
Legal Proceedings
From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case. That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds currently reflected in “Accounts payable and accrued liabilities” on the Company’s consolidated balance sheet.sheet as of December 31, 2019. The judgment, interest and fees were paid in April 2020.
In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the
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plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgment plus fees and interest. The Company has since prepared and filed an appeal with the appellate court for a review of the initial trial court’s decision. The plaintiff has petitioned the appellate court decision andfor an extension of time until late in the fourth quarter of 2020 in order to file briefs with the court. The Company is awaiting the court’s responseresponse.
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While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Throughput Contract Commitment
The Company signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and continued to not meet the minimum throughput requirements under the agreement through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in the second quarter of each calendar year. The Company incurred net fees of $0.2 million during each of the three months ended March 31, 2020 and 2019. As of December 31, 2019, the Company has recorded a $1.0 million loss contingency through the expiration of the contract on March 31, 2020, which is to be paid in three equal monthly installments beginning in August of 2020.
12. Subsequent Events
Paycheck Protection Program Loan
On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the CARES Act and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A.
The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.
Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during the eight-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to outstanding principal.
Sale of Assets
On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These properties were acquired during the Will Energy acquisition. The Company sold these properties in exchange for the buyer’s assumption of the asset retirement obligations associated with these wells, which is an estimated $4.9 million net to the Company.
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On June 5, 2020, the Company announced the addition of a new corporate strategy that includes offering a “fee for service” property management service for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million plus reimbursement of certain costs and expenses, an annual deferred fee of $2 million per year, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms of the warrants to be disclosed upon execution of the Warrant Agreement). Both companies and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owns approximately 56% of the common units in Mid-Con, and Travis Goff, the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.
Authorized Shares of Common Stock and Conversion of Series C Contingent Convertible Preferred Stock
On June 10, 2020, the Company filed an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock of the Company from 200,000,000 shares to 400,000,000 shares. The Charter Amendment and the conversion of 2,700,000 shares of the Company’s Series C contingent convertible preferred stock, par value $0.04 per share, into 2,700,000 shares of the Company’s common stock were approved by the stockholders of the Company on June 8, 2020, at the Company’s 2020 Annual Meeting of Stockholders. The shares of Series C contingent convertible preferred stock were issued in a private placement completed concurrently with a registered public offering of common stock in December 2019. Purchasers of the Series C contingent convertible preferred stock included John Goff, Wilkie Colyer and Farley Dakan.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and with our 2019 Form 10-K, previously filed with the Securities and Exchange Commission ("SEC"(“SEC”).
Available Information
General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. This report should be read together with our 2019 Form 10-K and our subsequent filings with the SEC. We are not including the information on our website as a part of, or incorporating it by reference into, this report.
Cautionary Statement about Forward-Looking Statements
Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report and in our 2019 Form 10-K and those factors summarized below:
● | volatility and significant declines in oil, natural gas and natural gas liquids |
● | any reduction in our borrowing base from time to time and our ability to repay any excess borrowings as a result of such reduction; |
● | the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders, and interruptions to our |
● |
● | our financial position; |
● | the impact of our derivative instruments; |
● | our business strategy, including execution of any changes in our |
● | meeting our forecasts and budgets, including our 2020 capital expenditure budget; |
● | expectations regarding oil and natural gas |
● | the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to and maintain oil price and production controls; |
● | outbreaks and pandemics, even outside our areas of operation, including COVID-19; |
● | operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and natural gas processing facilities; |
● | our ability to successfully develop our undeveloped acreage in the Southern Delaware Basin and the Mid-continent area of Oklahoma, and realize the benefits associated therewith; |
● | increased costs and risks associated with our exploration and development in the Gulf of Mexico; |
● | the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts and explosions, onshore and offshore; |
● | the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which we have made a large capital commitment relative to the size of our capitalization structure; |
● | the timing and successful drilling and completion of oil and natural gas |
● | the concentration of drilling in the Southern Delaware Basin, including lower than expected production attributable to down spacing of wells; |
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● | our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations, fund our drilling program and support our acquisition efforts; |
● | the cost and availability of rigs and other materials, services and operating equipment; |
● | timely and full receipt of sale proceeds from the sale of our production; |
● | our ability to find, acquire, market, develop and produce new oil and natural gas |
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● | the conditions of the capital markets and our ability to access debt and equity capital markets or other non-bank sources of financing, and actions by current and potential sources of capital, including lenders; |
● | interest rate volatility; |
● | our ability to successfully integrate the businesses, properties and assets we acquire, including those in new areas of operation; |
● | our ability to complete strategic dispositions or acquisitions of assets or businesses and realize the benefits of such dispositions or acquisitions; |
● | uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures; |
● | the need to take impairments on our properties due to lower commodity prices or other changes in the values of our assets; |
● | the ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by the Bureau of Ocean Energy Management; |
● | operating hazards attendant to the oil and natural gas |
● | downhole drilling and completion risks that are generally not recoverable from third parties or insurance; |
● | potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps; |
● | actions or inactions of third-party operators of our properties; |
● | actions or inactions of third-party operators of pipelines or processing facilities; |
● | the ability to retain key members of senior management and key technical employees and to find and retain skilled personnel; |
● | strength and financial resources of competitors; |
● | federal and state legislative and regulatory developments and approvals (including additional taxes and changes in environmental regulations); |
● | the |
● | our ability to obtain goods and services critical to the operation of our properties; |
● | worldwide and United States economic conditions; |
● | the ability to construct and operate infrastructure, including pipeline and production facilities; |
● | the continued compliance by us with various pipeline and gas processing plant specifications for the gas and condensate produced by us; |
● | operating costs, production rates and ultimate reserve recoveries of our oil and natural gas |
● | expanded rigorous monitoring and testing requirements; |
● | the ability to obtain adequate insurance coverage on commercially reasonable terms; and |
● | the limited trading volume of our common stock and general market volatility. |
Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. Moreover, the effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of the factors summarized above or discussed in this report or our 2019 Form 10-K.10-K or our Quarterly Report on Form 10-Q for the period ended March 31, 2020. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.
We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law.
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Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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Overview
We are a Houston, Texas based, independent oil and natural gas company, with regional offices in Oklahoma City and Stillwater, Oklahoma. Our business is to maximize production and cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas, Oklahoma, Louisiana and Wyoming properties and use that cash flow to explore, develop exploit, and acquire oil and natural gas properties across the United States.
From the Company’sour initial entry into the Southern Delaware Basin in 2016 and through mid-2019, the Company waswe have been focused on the development of itsour Southern Delaware Basin acreage in Pecos County, Texas. As of March 31,June 30, 2020, the Company waswe were producing from eighteen wells over our approximate 17,20016,200 gross operated (8,000(7,500 company net) acre position in this West Texas, area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.
During the fourth quarter of 2019, we closed on the acquisitions of certain producing assets and undeveloped acreage of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) and established an additional core strategic area, located primarily located in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative as production from these acquisitions represented 74%approximately 70% of our total net production for the first quarter ofthree and six months ended June 30, 2020.
In the fourth quarter of 2019, we also entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides us the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was spud in May 2020 and determined unsuccessful in June 2020.
During the three months ended June 30, 2020 we announced the addition of a new corporate strategy that includes offering a property management service (or “fee for service”) for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, we entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million, additional fees upon termination and warrants to align both parties and create value for shareholders. See Item 1. Note 1 – “Organization and Business” for additional information.
The following table lists our primary producing areas as of March 31,June 30, 2020:
Location |
| Formation |
Gulf of Mexico | | Offshore Louisiana - water depths less than 300 feet |
Mid-continent Region of Oklahoma | | Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork |
Southern Delaware Basin, Pecos County, Texas | | Wolfcamp A and B |
Madison and Grimes counties, Texas | | Woodbine / Upper Lewisville |
Zavala and Dimmit counties, Texas | | Buda / Eagle Ford / Georgetown |
San Augustine County, Texas | | Haynesville shale, Mid Bossier shale and James Lime formations |
Other Texas Gulf Coast | | Conventional and smaller unconventional formations |
Weston County, Wyoming | | Muddy Sandstone |
Sublette County, Wyoming | | Jonah Field (1) |
(1) | Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in our reported production results for all periods shown in this report. |
Impact of the COVID-19 Pandemic and 2020 Plan Changes
The COVID-19 pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and has created significant volatility, uncertainty and turmoil in the oil and gas industry. This has led to a significant global oversupply of oil and a subsequent substantial decrease in oil prices. While global oil producers, including the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing
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nations reached an agreement to cut oil production in April 2020, downward pressure on, and volatility in, commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for oil. We have certain commodity derivative instruments in place to mitigate the effects of such price declines; however, derivatives will not entirely mitigate lower oil prices. TheWhile there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond the Company’s control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, additional actions by businesses and governments in response to both the pandemic and the decrease in oil prices, the speed and effectiveness of responses to combat the virus, and the time necessary to equalize oil supply and demand to restore oil pricing. In response to these developments, we have implementedcontinued to implement measures to mitigate the impact of the COVID-19 pandemic on our employees, operations and financial position. These measures include, but are not limited to, the following:
● |
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● |
● |
● |
Additionally, on April 10, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and is administered by the U.S. Small Business Administration. Under the CARES Act, the PPP Loan may be partially or wholly forgiven following an audit if the funds are used for certain qualifying expenses. We intend to use the PPP Loan amount for qualifying expenses and will continue to assess whether to apply for forgiveness of the PPP Loan in accordance with the terms of the CARES Act.Act and related guidance. See Item 1. Note 1210 – “Subsequent Events”“Long-Term Debt” for additional information on the terms of the PPP Loan. We also benefited from certain income tax-related provisions of the CARES Act. See Item 1. Note 1011 – “Income Taxes” for additional informationinformation.
We continue to assess the global impacts of the COVID-19 pandemic and expect to continue to modify our plans as more clarity around the full economic impact of COVID-19 becomes available. See Part II, Item 1A. "Risk Factors"“Risk Factors” in our Quarterly Report on Form 10-Q for the period ended March 31, 2020 for further discussion.
Capital Expenditures
During the three months ended March 31, 2020, we brought one well onlineBeginning in the Southern Delaware Basin, the State Spearhead #1H, which is located in our NE Bullseye project area but suspended further drilling in the areasecond quarter of 2020, in response to the dramatic declinedecrease in oil prices during the quarter. Additionally, due to the recent decline in oilcommodity prices, we have suspended any further plans for onshore drilling in 2020. The offshore Iron Flea prospect in the shallow waters off of the Louisiana coast in Grand Isle was spud in late May 2020. On June 12, 2020, the target drilling depth was reached, and the prospect was determined unsuccessful. As a result, we recorded $10.9 million in dry hole exploration expenses during the three months ended June 30, 2020.
For 2020, we willplan to continue to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, while also searching for new resource acquisition opportunities. Acquisition efforts, if any, will be focused on areas in which we can leverage our geological and operational experience and expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to economically grow production and add reserves.
On June 5, 2020, the Company announced the addition of a new corporate strategy that includes offering a “fee for service” property management service for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) (Nasdaq: MCEP) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million plus reimbursement of certain costs and expenses, an annual deferred fee of $2 million per year, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms to be disclosed upon execution of the Warrant Agreement). Both companies and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owns approximately 56% of the common units in Mid-Con, and Travis Goff, the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.
Impairment of Long-Lived Assets
Under GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by fieldregion basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, oil and natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by the OPEC and Russia to reach an agreement on lower production quotas in Marchuntil April 2020, caused a dramatic increase in the supply of oil and a corresponding decrease in commodity prices, and lowered the demand for all commodity products. Consequently, during the three months ended March 31, 2020, we
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recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties related to the dramatic decline in commodity prices, as discussed above, the “PV-10” (present value, discounted at a 10%
28
rate) of our proved reserves, and the associated change in our current development plans for our proved, undeveloped locations. NoWe conducted an impairment of proved properties was recorded duringtest for the three months ended MarchJune 30, 2020, but no additional impairment was recorded. We recognized non-cash proved property impairment of $0.2 million for the six months ended June 30, 2019, related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2019.2018.
We recorded a $2.6 million non-cash charge for unproved impairment expense during the three months ended March 31, 2020. The impairment primarily related to acquired leases in the Company’s Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. DuringNo additional impairment was recorded during the three months ended March 31,June 30, 2020. During the six months ended June 30, 2019, we recorded non-cash impairment expense of $0.5$0.9 million related to impairment of certain unproved properties, primarily due to expiring leases.
Summary Production Information
Our production sales for the three months ended March 31,June 30, 2020 waswere approximately 85%83% onshore and 15%17% offshore, volumetrically, and was comprised of 50%56% natural gas, 30%24% oil and 20% natural gas liquids. During the second quarter of 2020, due to the extreme volatility in oil prices ranging from a low of ($37.63) per Bbl to a high of $40.46 per Bbl, we placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Our production sales for the three months ended March 31,June 30, 2019 was 35%were 41% onshore and 65%59% offshore, volumetrically, and was comprised of approximately 59%55% natural gas, 23%26% oil and 18%19% natural gas liquids.
The table below sets forth our average net daily production sales data in Mboe/d for each of our fieldsregions for each of the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Three Months Ended | | ||||||||||||||||
|
| March 31, 2019 |
| June 30, 2019 |
| September 30, 2019 |
| December 31, 2019 |
| March 31, 2020 |
|
| June 30, 2019 |
| September 30, 2019 |
| December 31, 2019 |
| March 31, 2020 |
| June 30, 2020 |
|
Offshore GOM | | 3.9 | | 3.2 | | 3.3 | | 3.2 | | 2.7 | | | 3.2 | | 3.3 | | 3.2 | | 2.7 | | 2.7 | |
Central Oklahoma (1) | | — | | — | | — | | 8.1 | | 10.9 | | |||||||||||
Central Oklahoma (1) (2) | | — | | — | | 8.1 | | 10.9 | | 9.1 | | |||||||||||
Western Anadarko (1) | | — | | — | | — | | 1.7 | | 2.9 | | | — | | — | | 1.7 | | 2.9 | | 2.5 | |
West Texas | | 1.0 | | 1.0 | | 0.9 | | 1.4 | | 1.2 | | | 1.0 | | 0.9 | | 1.4 | | 1.2 | | 0.9 | |
Other Onshore | | 1.1 | | 1.2 | | 1.4 | | 1.4 | | 1.2 | | | 1.2 | | 1.4 | | 1.4 | | 1.2 | | 0.9 | |
| | 6.0 | | 5.4 | | 5.6 | | 15.7 | | 18.9 | | | 5.4 | | 5.6 | | 15.7 | | 18.9 | | 16.1 | |
| | | | | | | | | | | | | | | | | | | | | | |
(1) | Properties acquired in the White Star and Will Energy acquisitions during the three months ended December 31, 2019. |
(2) | Decrease in production sales during the three months ended June 30, 2020 due to allocating approximately 50,000 Bbls of oil (net to the Company) to inventory storage (0.5 Mboe/d). |
(3) | Increase in production sales during the three months ended December 31, 2019 was due to new wells coming online. |
Other Investments
Jonah Field - Sublette County, Wyoming
Our wholly owned subsidiary, Contaro Company, owns a 37% ownership interest in Exaro. As of March 31,June 30, 2020, Exaro had 645 wells on production over its 5,760 gross acres (1,040 net), with a working interest between 14.6% and 32.5%. These wells were producing at a rate of approximately 2.72.8 Mboe/d, net to Exaro.Exaro, during the three months ended June 30, 2020. As a result of our equity investmentnvestment in Exaro, we recognized aan investment loss of approximately $0.2 million, net of no tax expense, and an investment gain of approximately $0.3$0.4 million, net of no tax expense, for each of the three months ended March 31,June 30, 2020 and 2019, respectively. We recognized an investment gain of approximately $0.1 million, net of no tax expense, and an investment gain of approximately $0.7 million, net of no tax expense, for the six months ended June 30, 2020 and 2019, respectively. See Item 1. Note 89 – “Investment in Exaro Energy III LLC” for additional details related to this equity investment.
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Results of Operations for the Three and Six Months ended March 31,June 30, 2020 and 2019
The table below sets forth revenue, production data, average sales prices and average production costs associated with our sales of oil, natural gas oil and natural gas liquids ("NGLs") from operations for the three and six months ended March 31,June 30, 2020 and 2019. Natural gas is compared with oil, condensate and NGLsIn the first quarter of 2020, we began reporting in terms of thousands of barrels of oil equivalents (“Boe”) instead of natural gas equivalents. Six thousand cubic feet (“Mcf”) of natural gas is the energy equivalent of one barrel of oil, condensate or NGL. Reported operating expenses include production taxes, such as ad valorem and severance taxes.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | | Three Months Ended June 30, | | | Six Months Ended June 30, | | ||||||||||||||||||
|
| 2020 |
| 2019 |
| % |
| |
| 2020 |
| 2019 |
| % |
| | 2020 | | 2019 | | % |
| ||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenues (thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and condensate sales | | $ | 22,782 | | $ | 6,406 | | 256 | % | | | $ | 7,930 | | $ | 7,439 | | 7 | % | | $ | 30,712 | | $ | 13,845 | | 122 | % |
Natural gas sales | | | 8,170 | | | 5,642 | | 45 | % | | | | 6,618 | | | 3,857 | | 72 | % | | | 14,789 | | | 9,499 | | 56 | % |
NGL sales | | | 3,621 | | | 1,963 | | 84 | % | | | | 3,294 | | | 1,466 | | 125 | % | | | 6,915 | | | 3,429 | | 102 | % |
Total revenues | | $ | 34,573 | | $ | 14,011 | | 147 | % | | | $ | 17,842 | | $ | 12,762 | | 40 | % | | $ | 52,416 | | $ | 26,773 | | 96 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Production: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and condensate (thousand barrels) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 9 | | | 13 | | (31) | % | | | | 8 | | | 10 | | (20) | % | | | 18 | | | 23 | | (22) | % |
Central Oklahoma | | | 289 | | | — | | 100 | % | | | | 174 | | | — | | 100 | % | | | 463 | | | — | | 100 | % |
Western Anadarko | | | 77 | | | — | | 100 | % | | | | 57 | | | — | | 100 | % | | | 135 | | | — | | 100 | % |
West Texas | | | 89 | | | 64 | | 39 | % | | | | 69 | | | 60 | | 15 | % | | | 158 | | | 125 | | 26 | % |
Other Onshore | | | 56 | | | 48 | | 17 | % | | | | 38 | | | 57 | | (33) | % | | | 92 | | | 105 | | (12) | % |
Total oil and condensate | | | 520 | | | 125 | | 316 | % | | | | 346 | | | 127 | | 172 | % | | | 866 | | | 253 | | 242 | % |
Natural gas (million cubic feet) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 1,263 | | | 1,635 | | (23) | % | | | | 1,222 | | | 1,325 | | (8) | % | | | 2,485 | | | 2,960 | | (16) | % |
Central Oklahoma | | | 2,817 | | | — | | 100 | % | | | | 2,637 | | | — | | 100 | % | | | 5,479 | | | — | | 100 | % |
Western Anadarko | | | 827 | | | — | | 100 | % | | | | 814 | | | — | | 100 | % | | | 1,642 | | | — | | 100 | % |
West Texas | | | 50 | | | 64 | | (22) | % | | | | 31 | | | 88 | | (65) | % | | | 81 | | | 152 | | (47) | % |
Other Onshore | | | 244 | | | 194 | | 26 | % | | | | 209 | | | 215 | | (3) | % | | | 428 | | | 409 | | 5 | % |
Total natural gas | | | 5,201 | | | 1,893 | | 175 | % | | | | 4,913 | | | 1,628 | | 202 | % | | | 10,115 | | | 3,521 | | 187 | % |
Natural gas liquids (thousand barrels) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 30 | | | 66 | | (55) | % | | | | 37 | | | 58 | | (36) | % | | | 67 | | | 124 | | (46) | % |
Central Oklahoma | | | 232 | | | — | | 100 | % | | | | 215 | | | — | | 100 | % | | | 450 | | | — | | 100 | % |
Western Anadarko | | | 46 | | | — | | 100 | % | | | | 32 | | | — | | 100 | % | | | 78 | | | — | | 100 | % |
West Texas | | | 9 | | | 14 | | (36) | % | | | | 6 | | | 15 | | (60) | % | | | 15 | | | 29 | | (48) | % |
Other Onshore | | | 16 | | | 18 | | (11) | % | | | | 15 | | | 19 | | (21) | % | | | 27 | | | 37 | | (27) | % |
Total natural gas liquids | | | 333 | | | 98 | | 240 | % | | | | 305 | | | 92 | | 232 | % | | | 637 | | | 190 | | 235 | % |
Total (thousand barrels of oil equivalent) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 250 | | | 352 | | (29) | % | | | | 249 | | | 289 | | (14) | % | | | 499 | | | 641 | | (22) | % |
Central Oklahoma | | | 991 | | | — | | 100 | % | | | | 828 | | | — | | 100 | % | | | 1,827 | | | — | | 100 | % |
Western Anadarko | | | 261 | | | — | | 100 | % | | | | 225 | | | — | | 100 | % | | | 486 | | | — | | 100 | % |
West Texas | | | 106 | | | 89 | | 19 | % | | | | 80 | | | 90 | | (11) | % | | | 186 | | | 179 | | 4 | % |
Other Onshore | | | 112 | | | 98 | | 14 | % | | | | 87 | | | 111 | | (22) | % | | | 191 | | | 210 | | (9) | % |
Total production | | | 1,720 | | | 539 | | 219 | % | | | | 1,469 | | | 490 | | 200 | % | | | 3,189 | | | 1,030 | | 210 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Daily Production: | | | | | | | | | | | | | | | | | ||||||||||||
Oil and condensate (thousand barrels per day) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 0.1 | | | 0.1 | | (31) | % | | | | 0.1 | | | 0.1 | | — | % | | | 0.1 | | | 0.1 | | — | % |
Central Oklahoma | | | 3.2 | | | — | | 100 | % | | | | 1.9 | | | — | | 100 | % | | | 2.5 | | | — | | 100 | % |
Western Anadarko | | | 0.8 | | | — | | 100 | % | | | | 0.6 | | | — | | 100 | % | | | 0.7 | | | — | | 100 | % |
West Texas | | | 1.0 | | | 0.7 | | 39 | % | | | | 0.8 | | | 0.7 | | 14 | % | | | 0.9 | | | 0.7 | | 29 | % |
Other Onshore | | | 0.6 | | | 0.6 | | 17 | % | | | | 0.3 | | | 0.6 | | (50) | % | | | 0.6 | | | 0.6 | | — | % |
Total oil and condensate | | | 5.7 | | | 1.4 | | 316 | % | | | | 3.7 | | | 1.4 | | 164 | % | | | 4.8 | | | 1.4 | | 243 | % |
3031
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | | Three Months Ended June 30, | | | Six Months Ended June 30, | | ||||||||||||||||||
|
| 2020 |
| 2019 |
| % |
| |
| 2020 |
| 2019 |
| % |
| | 2020 | | 2019 | | % |
| ||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (million cubic feet per day) | | | | | | | | | | | | | | | | | | | | | | | | | ||||
Offshore GOM | | | 13.9 | | | 18.2 | | (23) | % | | | | 13.4 | | | 14.6 | | (8) | % | | | 13.7 | | | 16.4 | | (16) | % |
Central Oklahoma | | | 31.0 | | | — | | 100 | % | | | | 29.0 | | | — | | 100 | % | | | 30.1 | | | — | | 100 | % |
Western Anadarko | | | 9.1 | | | — | | 100 | % | | | | 8.9 | | | — | | 100 | % | | | 9.0 | | | — | | 100 | % |
West Texas | | | 0.5 | | | 0.7 | | (22) | % | | | | 0.3 | | | 1.0 | | (70) | % | | | 0.4 | | | 0.8 | | (50) | % |
Other Onshore | | | 2.7 | | | 2.1 | | 26 | % | | | | 2.4 | | | 2.3 | | 4 | % | | | 2.4 | | | 2.3 | | 4 | % |
Total natural gas | | | 57.2 | | | 21.0 | | 175 | % | | | | 54.0 | | | 17.9 | | 202 | % | | | 55.6 | | | 19.5 | | 185 | % |
Natural gas liquids (thousand barrels per day) | | | | | | | | | | | | | | | | | | | | | | | | | ||||
Offshore GOM | | | 0.3 | | | 0.7 | | (55) | % | | | | 0.4 | | | 0.6 | | (33) | % | | | 0.4 | | | 0.7 | | (43) | % |
Central Oklahoma | | | 2.5 | | | — | | 100 | % | | | | 2.4 | | | — | | 100 | % | | | 2.5 | | | — | | 100 | % |
Western Anadarko | | | 0.5 | | | — | | 100 | % | | | | 0.4 | | | — | | 100 | % | | | 0.4 | | | — | | 100 | % |
West Texas | | | 0.1 | | | 0.2 | | (36) | % | | | | 0.1 | | | 0.2 | | (50) | % | | | 0.1 | | | 0.2 | | (50) | % |
Other Onshore | | | 0.3 | | | 0.2 | | (11) | % | | | | 0.1 | | | 0.2 | | (50) | % | | | 0.2 | | | 0.1 | | 100 | % |
Total natural gas liquids | | | 3.7 | | | 1.1 | | 240 | % | | | | 3.4 | | | 1.0 | | 240 | % | | | 3.6 | | | 1.0 | | 260 | % |
Total (thousand barrels of oil equivalent per day) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Offshore GOM | | | 2.7 | | | 3.9 | | (29) | % | | | | 2.7 | | | 3.2 | | (16) | % | | | 2.7 | | | 3.5 | | (23) | % |
Central Oklahoma | | | 10.9 | | | — | | 100 | % | | | | 9.1 | | | — | | 100 | % | | | 10.0 | | | — | | 100 | % |
Western Anadarko | | | 2.9 | | | — | | 100 | % | | | | 2.5 | | | — | | 100 | % | | | 2.7 | | | — | | 100 | % |
West Texas | | | 1.2 | | | 1.0 | | 19 | % | | | | 0.9 | | | 1.0 | | (10) | % | | | 1.0 | | | 1.0 | | — | % |
Other Onshore | | | 1.2 | | | 1.1 | | 14 | % | | | | 0.9 | | | 1.2 | | (25) | % | | | 1.2 | | | 1.2 | | — | % |
Total production | | | 18.9 | | | 6.0 | | 219 | % | | | | 16.1 | | | 5.4 | | 198 | % | | | 17.6 | | | 5.7 | | 209 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Average Sales Price: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and condensate (per barrel) | | $ | 43.77 | | $ | 51.08 | | (14) | % | | | $ | 22.94 | | $ | 58.42 | | (61) | % | | $ | 35.46 | | $ | 54.78 | | (35) | % |
Natural gas (per thousand cubic feet) | | $ | 1.57 | | $ | 2.98 | | (47) | % | | | $ | 1.35 | | $ | 2.37 | | (43) | % | | $ | 1.46 | | $ | 2.70 | | (46) | % |
Natural gas liquids (per barrel) | | $ | 10.89 | | $ | 19.96 | | (45) | % | | | $ | 10.81 | | $ | 16.01 | | (32) | % | | $ | 10.85 | | $ | 18.05 | | (40) | % |
Total (per barrels of oil equivalent) | | $ | 20.10 | | $ | 25.98 | | (23) | % | | | $ | 12.14 | | $ | 26.03 | | (53) | % | | $ | 16.43 | | $ | 26.00 | | (37) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Expenses (thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating expenses | | $ | 21,483 | | $ | 5,192 | | 314 | % | | | $ | 17,139 | | $ | 5,694 | | 201 | % | | $ | 38,621 | | $ | 10,886 | | 255 | % |
Exploration expenses | | $ | 398 | | $ | 224 | | 78 | % | | | $ | 11,173 | | $ | 249 | | * | % | | $ | 11,571 | | $ | 473 | | * | % |
Depreciation, depletion and amortization | | $ | 12,854 | | $ | 7,556 | | 70 | % | | | $ | 5,092 | | $ | 7,573 | | (33) | % | | $ | 17,946 | | $ | 15,129 | | 19 | % |
Impairment and abandonment of oil and gas properties | | $ | 145,878 | | $ | 587 | | * | % | | | $ | — | | $ | 1,247 | | * | % | | $ | 145,878 | | $ | 1,834 | | * | % |
General and administrative expenses | | $ | 5,425 | | $ | 5,005 | | 8 | % | | | $ | 5,713 | | $ | 4,456 | | 28 | % | | $ | 11,138 | | $ | 9,461 | | 18 | % |
Gain from investment in affiliates (net of taxes) | | $ | 286 | | $ | 30 | | 853 | % | | ||||||||||||||||||
Gain (loss) from investment in affiliates (net of taxes) | | $ | (173) | | $ | 427 | | (141) | % | | $ | 113 | | $ | 457 | | (75) | % | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Selected data per Boe: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating expenses | | $ | 12.49 | | $ | 9.63 | | 30 | % | | | $ | 11.67 | | $ | 11.62 | | — | % | | $ | 12.11 | | $ | 10.57 | | 15 | % |
General and administrative expenses | | $ | 3.15 | | $ | 9.29 | | (66) | % | | | $ | 3.89 | | $ | 9.09 | | (57) | % | | $ | 3.49 | | $ | 9.19 | | (62) | % |
Depreciation, depletion and amortization | | $ | 7.47 | | $ | 14.02 | | (47) | % | | | $ | 3.47 | | $ | 15.46 | | (78) | % | | $ | 5.63 | | $ | 14.69 | | (62) | % |
*Greater than 1,000%
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
Three Months Ended March 31,June 30, 2020 Compared to Three Months Ended March 31,June 30, 2019
Natural Gas, Oil and NGL Sales and Production
All of ourOur revenues are primarily from the sale of our oil, natural gas oil,and NGL and water production. Our revenues may vary significantly from year to year depending on production volumes and changes in commodity prices, each of which may fluctuate widely. As discussed above, oil prices declined significantly in the first quarter of 2020 as a result of the effects of the COVID-19 pandemic and the ongoing disruptions to the global energy markets.markets and, while there have been modest recoveries of commodity prices, downward pressure on, and volatility in, commodity prices continued during the second quarter of 2020. Our production volumes are subject to significant variation as a result of new operations, weather events,
32
transportation and processing constraints and mechanical issues. In addition, our production from individual wells naturally declines over time as we produce our reserves.
31
We reported revenues of $34.6$17.8 million for the three months ended March 31,June 30, 2020, compared to revenues of $14.0$12.8 million for the three months ended March 31,June 30, 2019, an increase even as prices declined, attributable primarily to the production from the properties acquired from Will Energy and White Star.Star, offset in part by the 53% decrease in the weighted average equivalent sales price period over period.
Total equivalent production was 18.916.1 Mboe/d for the three months ended March 31,June 30, 2020, compared to 6.05.4 Mboe/d in the prior year quarter, an increase attributable to the additional production from the Will Energy and White Star acquisitions.properties acquired in the fourth quarter of 2019. Net oil production for the current quarter was approximately 5.73.7 Mbbl/d, compared with approximately 1.4 Mbbl/d in the prior year quarter. During the current year quarter, due to the extreme volatility in oil prices, which ranged from a low of ($37.63) per Bbl to a high of $40.46 Bbl, the Company placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Net natural gas production for the current quarter was approximately 57.254.0 Mmcf/d, compared with approximately 21.017.9 Mmcf/d in the prior year quarter, and NGL production for the current quarter was approximately 3.73.4 Mbbl/d, compared with approximately 1.11.0 Mbbl/d in the prior year quarter.
Average Sales Prices
The average equivalent sales price realized for the three months ended March 31,June 30, 2020 was $20.10$12.14 per Boe compared to $25.98$26.03 per Boe for the three months ended March 31,June 30, 2019. The decline was attributable to the decrease in all realized commodity prices in the current year quarter, as a result of the decrease inquarter. The COVID-19 pandemic continued to adversely impact demand for commodity products, duewhich caused a global supply/demand imbalance for oil that resulted in extreme volatility in benchmark oil prices, with prices ranging from a low of ($37.63) per Bbl to a high of $40.46 per Bbl during the COVID-19 pandemic and the failure of OPEC and Russia to reach an agreement on oil production quotas in March 2020.second quarter. The realized price of oil was $43.77averaged $22.94 per Bbl in the current quarter, compared to $51.08an average $58.42 per Bbl in the prior year quarter. Natural gas prices also suffered due to the COVID-19 pandemic, ranging from a low of $1.48 per Mcf to a high of $2.13 per MCF during the current year quarter. The realized price of gas was $1.57averaged $1.35 per Mcf in the current quarter compared to $2.98an average of $2.37 per Mcf in the prior year quarter, and the realized price of NGLs was $10.89averaged $10.81 per Bbl in the current quarter compared to $19.96an average $16.01 per Bbl in the prior year quarter.
Operating Expenses
Operating expenses for the three months ended March 31,June 30, 2020 were approximately $21.5$17.1 million, or $12.49$11.67 per Boe, compared to $5.2$5.7 million, or $9.63$11.62 per Boe, for the three months ended March 31,June 30, 2019. The table below provides additional detail of operating expenses for the three month periods:
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | Three Months Ended June 30, | | ||||||||||||||||
|
| 2020 |
| 2019 |
|
| 2020 |
| 2019 |
| ||||||||||||
|
| (in thousands) |
| (per Boe) |
| (in thousands) |
| (per Boe) | |
| (in thousands) |
| (per Boe) |
| (in thousands) |
| (per Boe) | | ||||
Lease operating expenses | | $ | 13,051 | | $ 7.59 | | $ | 3,685 | | $ 6.84 | | | $ | 11,136 | | $ 7.58 | | $ | 3,629 | | $ 7.41 | |
Production & ad valorem taxes | | | 1,746 | | 1.02 | | | 386 | | 0.72 | | | | 828 | | 0.56 | | | 657 | | 1.34 | |
Transportation & processing costs | | | 5,552 | | 3.23 | | | 695 | | 1.29 | | | | 4,579 | | 3.12 | | | 502 | | 1.02 | |
Workover costs | | | 1,134 | | 0.65 | | | 426 | | 0.78 | | | | 596 | | 0.41 | | | 906 | | 1.85 | |
Total operating expenses | | $ | 21,483 | | 12.49 | | $ | 5,192 | | $ 9.63 | | | $ | 17,139 | | 11.67 | | $ | 5,694 | | $ 11.62 | |
Lease operating expenses increased $9.4were $11.1 million compared toand $3.6 million for the prior year quarter,three months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our acquired properties.
Production and ad valorem taxes increased $1.4 million compared to the prior year quarter, primarily related to the Will Energy and White Star property acquisitions.acquired properties.
Transportation and processing costs increased $4.9were $4.6 million compared to the prior year quarter due to additional transportation expense of $5.1 million, primarily related to the properties acquired in the White Star acquisition.
Workover costs increased $0.7and $0.5 million for the three months ended March 31,June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties and the related higher transportation costs in our Central Oklahoma region.
33
Exploration Expense
Exploration expense was $11.2 million for the three months ended June 30, 2020, compared to the prior year quarter of $0.2 million, an increase primarily due to $10.9 million of dry hole costs related to workoversthe unsuccessful result on properties acquired from White Star.the drilling of the Iron Flea exploratory prospect in the shallow waters in the Grand Isle area of the Gulf of Mexico.
Impairment and Abandonment Expenses
During the three months ended March 31,June 30, 2020, we recorded a $143.3 million non-cash charge for proved propertydid not record any impairment ofrelated to our onshore properties as a result of the dramatic decline in commodity prices, the “PV-10” (present value, discounted at a 10% rate) of our proved reserves, and the associated change in our current development plans for proved, undeveloped locations. No impairment of proved properties was recorded duringproperties. During the three months ended MarchJune 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2019.2018.
32
During the three months ended March 31,June 30, 2020, we recorded a $2.6 millionalso did not record any impairment expense on unproved properties. In the 2019 quarter, we recognized non-cash charge for unproved impairment expense of approximately $0.4 million, primarily related primarily to acquiredexpiring leases, in our Central Oklahoma and Western Anadarko regions, which will be expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. During the three months ended March 31, 2019, we recorded non-cash impairmentan abandonment expense of $0.5 million related to impairment of certain unproved properties, primarily due to expiring leases.$0.6 million.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense for the three months ended March 31,June 30, 2020, was approximately $12.9$5.1 million, or $7.47$3.47 per Boe. This compares to approximately $7.6 million, or $14.02$15.46 per Boe, for the three months ended March 31,June 30, 2019. The higherlower depletion expense in the current quarter was a result of lower depletable property balances in the current quarter attributable to $7.8 million of additional expense recognized for our acquired properties, while the lower unit rate reflects the lower purchase price per barrel for our acquired properties ($6.08 per Boe) and a reduction in the Gulf of Mexico rate due toproved property impairment recorded during the fourthfirst quarter of 2019.2020.
General and Administrative Expenses
Total general and administrative expenses for the three months ended March 31,June 30, 2020 were approximately $5.4$5.7 million, compared to $5.0$4.5 million for the three months ended March 31,June 30, 2019.
The table below provides additional detail of general and administrative expenses for the comparative three month periods:
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | Three Months Ended June 30, | | ||||||||
|
| 2020 | �� | 2019 |
|
| 2020 |
| 2019 |
| ||||
| | (in thousands) | | | (in thousands) | | ||||||||
Wages, bonuses and employee benefits (1) | | $ | 2,568 | | $ | 850 | | | $ | 3,366 | | $ | 1,504 | |
Non-cash stock-based compensation (2) | | | 350 | | | 1,052 | | | | 266 | | | 584 | |
Professional fees (3) | | | 1,616 | | | 1,107 | | | | 2,039 | | | 1,021 | |
Professional fees - special (4) | | | 783 | | | 751 | | | | 551 | | | 985 | |
Other (5) | | | 108 | | | 1,245 | | |||||||
Recouped overhead (5) | | | (2,761) | | | (298) | | |||||||
Other (6) | | | 2,252 | | | 660 | | |||||||
Total general and administrative expenses | | $ | 5,425 | | $ | 5,005 | | | $ | 5,713 | | $ | 4,456 | |
(1) | Higher expenses for the three months ended |
(2) | Lower expense for the three months ended |
(3) | Primarily includes fees related to recurring legal counsel, technical consultants and accounting and auditing costs. |
(4) | Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives, including the integration of the White Star and Will Energy assets acquired during the three months ended December 31, 2019. |
(5) | These credits relate to overhead for our properties for which we are able to bill out to partners and offset against our other general and administrative costs. The increase in the current year credit is due to the additional overhead related to the acquired Will Energy and White Star properties. |
(6) | Includes fees related to insurance, office costs and other company expenses. The |
34
Gain (Loss) from Affiliates
For the three months ended March 31,June 30, 2020 and March 31,June 30, 2019, we recorded a gainloss from affiliates of approximately $0.3$0.2 million, net of no tax expense, and a gain of $0.4 million, net of no tax expense, respectively, related to our equity investment in Exaro.
Gain from Sale of Assets
During the three months ended June 30, 2020, we recorded a gain on sale of assets of $4.4 million related to the divestiture of non-core properties we acquired from Will Energy and White Star in the fourth quarter of 2019. The recorded gain resulted primarily from the buyer’s assumption of the asset retirement obligation on the properties. During the three months ended June 30, 2019, we recorded a gain on sales of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2019. See Item 1. Note 3 – “Dispositions” for additional information regarding these sales.
Gain (Loss) on Derivatives
During the three months ended June 30, 2020, we recorded a loss on derivatives of $8.8 million. Of this amount, $20.2 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at the end of the first quarter of 2020, offset in part by $11.4 million in realized gains during the second quarter. During the three months ended June 30, 2019, we recorded a gain on derivatives of $2.1 million. Of this amount, $1.6 million were non-cash, unrealized mark-to-market gains, and the remaining $0.5 million were realized gains.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019
Natural Gas, Oil and NGL Sales and Production
Our revenues are primarily from the sale of our oil, natural gas and NGL production. Our revenues may vary significantly from year to year depending on production volumes and changes in commodity prices, each of which may fluctuate widely. As discussed above, oil prices declined significantly in the first quarter of 2020 as a result of the effects of the COVID-19 pandemic and the ongoing disruptions to the global energy markets. Prices recovered somewhat during the second quarter of 2020, but still remained below those of the prior year periods. Our production volumes are subject to significant variation as a result of new operations, weather events, transportation and processing constraints and mechanical issues. In addition, our production from individual wells naturally declines over time as we produce our reserves.
We reported revenues of $52.4 million for the six months ended June 30, 2020, compared to revenues of $26.8 million for the six months ended June 30, 2019, an increase attributable primarily to the production from the properties acquired from Will Energy and White Star, offset in part by lower prices period over period.
Total equivalent production was 17.6 Mboe/d for the six months ended June 30, 2020, compared to 5.7 Mboe/d in the prior year, an increase attributable to the additional production from the Will Energy and White Star properties acquired in the fourth quarter of 2019. Net oil production for the current year was approximately 4.8 Mboe/d, compared with approximately 1.4 Mboe/d in the prior year. Due to the precipitous drop in oil prices at the beginning of the second quarter of 2020, the Company placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Net natural gas production for the current year was approximately 55.6 Mmcf/d, compared with approximately 19.5 Mmcf/d in the prior year, and NGL production for the current year was approximately 3.6 Mboe/d, compared with approximately 1.0 Mboe/d in the prior year.
Average Sales Prices
The average equivalent sales price realized for the six months ended June 30, 2020 was $16.43 per Boe compared to $26.00 per Boe for the six months ended June 30, 2019. The decline was attributable to the decrease in all realized commodity prices in the current year. The COVID-19 pandemic continued to adversely impact demand for commodity products, which caused a global supply/demand imbalance for oil that resulted in benchmark oil prices ranging from a high of $63.27 per Bbl at the beginning of 2020 to a low of ($37.63) per Bbl during the second quarter of 2020. The
35
realized price of oil averaged $35.46 per Bbl in the current year, compared to an average of $54.78 per Bbl in the prior year. Natural gas prices also suffered due to the COVID-19 pandemic, ranging from a low of $1.48 per Mcf to a high of $2.20 per Mcf during the current year. The realized price of gas averaged $1.46 per Mcf in the current year compared to an average of $2.70 per Mcf in the prior year, and the realized price of NGLs averaged $10.85 per Bbl in the current year compared to an average of $18.05 per Bbl in the prior year.
Operating Expenses
Operating expenses for the six months ended June 30, 2020 were approximately $38.6 million, or $12.11 per Boe, compared to $10.9 million, or $10.57 per Boe, for the six months ended June 30, 2019. The table below provides additional detail of operating expenses for the six month periods:
| | | | | | | | | | | |
| | Six Months Ended June 30, | | ||||||||
| | 2020 | | 2019 | | ||||||
| | | (in thousands) |
| (per Boe) |
| | (in thousands) |
| (per Boe) | |
Lease operating expenses | | $ | 24,187 | | $ 7.57 | | $ | 7,314 | | $ 7.10 | |
Production & ad valorem taxes | | | 2,574 | | 0.81 | | | 1,043 | | 1.01 | |
Transportation & processing costs | | | 10,131 | | 3.18 | | | 1,197 | | 1.16 | |
Workover costs | | | 1,729 | | 0.55 | | | 1,332 | | 1.30 | |
Total operating expenses | | $ | 38,621 | | 12.11 | | $ | 10,886 | | $ 10.57 | |
Lease operating expenses were $24.2 million and $7.3 million for the six months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties.
Production and ad valorem taxes were $2.6 million and $1.0 million for the six months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily related to the additional production in 2020 from the acquired Will Energy and White Star properties.
Transportation and processing costs were $10.1 million and $1.2 million for the six months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties and the related higher transportation costs in our Central Oklahoma region.
Exploration Expense
Exploration expense was $11.6 million for the six months ended June 30, 2020, compared to the prior year of $0.5 million, an increase primarily due to $10.9 million of dry hole costs related to the unsuccessful result on the drilling of the Iron Flea exploratory prospect in the shallow waters of the Grand Isle area of the Gulf of Mexico.
Impairment and Abandonment Expenses
During the six months ended June 30, 2020, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties due to the dramatic decline in commodity prices, and the impact of that decline on the “PV-10” (present value, discounted at a 10% rate) of our proved reserves and the associated change in our current development plans for proved, undeveloped locations (“PUDs”). Under GAAP, we are required to impair the balance sheet carrying cost of our proved property base to reflect that overall decrease in reserve value related to the decrease in prices and the reduction in PUDs. During the six months ended June 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.
During the six months ended June 30, 2020, we recorded a $2.6 million non-cash charge for unproved impairment expense related primarily to acquired leases in our Central Oklahoma and Western Anadarko regions, which will be expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. During the six months ended June 30, 2019, we recognized non-cash impairment expense of $0.9 million related to impairment of certain non-core unproved properties primarily due to expiring leases.
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Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense for the six months ended June 30, 2020, was approximately $17.9 million, or $5.63 per Boe. This compares to approximately $15.1 million, or $14.69 per Boe, for the six months ended June 30, 2019. The higher depletion expense in the current year was attributable to the additional properties acquired from Will Energy and White Star. The lower rate was a result of lower depletable property balances in the current quarter as a result of the proved property impairment recorded during the first quarter of 2020.
General and Administrative Expenses
Total general and administrative expenses for the six months ended June 30, 2020 were approximately $11.1 million, compared to $9.5 million for the six months ended June 30, 2019.
The table below provides additional detail of general and administrative expenses for the comparative six month periods:
| | | | | | | |
| | Six Months Ended June 30, | | ||||
|
| 2020 |
| 2019 |
| ||
| | (in thousands) | | ||||
Wages, bonuses and employee benefits (1) | | $ | 5,934 | | $ | 2,571 | |
Non-cash stock-based compensation (2) | | | 616 | | | 1,637 | |
Professional fees (3) | | | 3,655 | | | 2,128 | |
Professional fees - special (4) | | | 1,334 | | | 1,736 | |
Recouped overhead (5) | | | (5,668) | | | (514) | |
Other (6) | | | 5,267 | | | 1,903 | |
Total general and administrative expenses | | $ | 11,138 | | $ | 9,461 | |
(1) | Higher expenses for the six months ended June 30, 2020 due to the acquisition of certain Will Energy and White Star employees during the three months ended December 31, 2019. |
(2) | Lower expense for the six months ended June 30, 2020, due to restricted stock grants being awarded in the third quarter of 2020 as compared to the first quarter of 2019. |
(3) | Primarily includes fees related to recurring legal counsel, technical consultants and accounting and auditing costs. |
(4) | Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives, including the acquisition and integration of the White Star and Will Energy assets acquired during the three months ended December 31, 2019. |
(5) | These credits relate to overhead for our properties for which we are able to bill out to partners and offset against our other general and administrative costs. The increase in the current year credit is due to the additional overhead related to the acquired Will Energy and White Star properties. |
(6) | Includes fees related to insurance, office costs and other company expenses. The increase in the current year expense is primarily due to the additional expenses related to the acquired Will Energy and White Star properties, offices and employees. |
Gain from Affiliates
For the six months ended June 30, 2020 and June 30, 2019, we recorded a gain from affiliates of approximately $0.1 million and $0.7 million, net of no tax expense, respectively, related to our equity investment in Exaro.
Gain from Sale of Assets
For the six months ended June 30, 2020, we recorded a gain on sale of assets of $4.4 million related to the divestiture of non-core properties we acquired from Will Energy and White Star in the fourth quarter of 2019. The recorded gain resulted primarily from the buyer’s assumption of the asset retirement obligation on the properties. During the six months ended June 30, 2019, we recorded a gain on sales of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2019. See Item 1. Note 3 – “Dispositions” for additional information regarding these sales.
Gain (Loss) on Derivatives
During the six months ended June 30, 2020, we recorded a gain on derivatives of $37.9 million. Of this amount, $21.2 million were non-cash, unrealized mark-to-market gains as commodity prices declined from 2019 year-end levels, and $16.7 million were realized gains as derivative contracts were settled each month during the period. During the six
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months ended June 30, 2019, we recorded a loss on derivatives of $0.8 million. Of this amount, $2.1 million were non-cash, unrealized mark-to-market losses, and the remaining $1.3 million were realized gains.
Capital Resources and Liquidity
Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on debt. Our primary sources of liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our Credit Agreement (as defined below).
During the threesix months ended March 31,June 30, 2020, we incurred onshore expenditures of approximately $4.0$5.2 million on capital projects, including $2.0$2.6 million for our drilling and completion program in the Southern Delaware Basin. We broughtBasin to bring one newly-drilled West Texas well on production and commenced the drilling ofto drill a salt water disposal well, in West Texas. Additionally, we paid a $7.1 million deposit for the turnkey drilling of the offshore Iron Flea prospect, currently included in “Deposits and other” on our consolidated balance sheet at March 31, 2020, which will be reclassed to exploration expense in the second quarter of 2020, due to theas well being unsuccessful. The current quarter also included
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approximately $0.9as $0.8 million in leasehold acquisition costs primarily related to our acreage in the Southern Delaware Basin.same region. The remaining incurred onshore capital expenditures arerelated primarily related to capitalized workovers.
During the six months ended June 30, 2020 we recorded exploration expenses of $10.9 million related to the drilling of the unsuccessful offshore exploratory Iron Flea prospect drilled in the shallow waters of the Gulf of Mexico. $2.7 million of the exploration expense related to the acquisition costs incurred in 2019 which were reclassified to exploration expense in 2020 as a result of the dry hole.
Our total capital expenditure program for the year 2020 is forecast at approximately $16.4 million.$19.0 million, including the expenses associated with the Iron Flea exploratory prospect. Due to the low and volatile commodity price environment, the Company has suspended any further plans for onshore drilling and completions in 2020. WeFor the remainder of 2020, we currently expect to limit our onshore capital expenditures to the completion of the salt water disposal well and related infrastructure in West Texas ($3.7 million), limited$5.5 million for workovers ($3.3 million) which are intended to increase cashflow through enhanced production and cashflow, andor reductions in recurring costs, required onshore plugging and abandonment activity ($0.7 million).and West Texas infrastructure. We expect that our only offshore capital expenditures for the remainder of 2020 will be the Iron Fleafocused on the evaluation and development of another exploratory well, which was spudprospect that may be drilled in late May 2020 and resulted in a dry hole. During the three months ended March 31, 2020, we paid a $7.1 million deposit for the turnkey drilling of the Iron Flea prospect, as explained above.early 2021.
We believe that our internally generated cash flows, combined with availability under the Credit Agreement (as defined below), will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve months; however, should our results of operations be less than expected, or we experience additional reductions in our borrowing base, we may need to pursue additional sources of liquidity such as monetization of a portion of our hedge portfolio or access the debt and equity markets, as available, to finance any necessary capital development and/or repay excess borrowings under our Credit Agreement, but there can be no assurance such incremental financing will be available to us or not result in dilution of our stockholders or increase our debt service costs. The COVID-19 pandemic and the ongoing disruptions to the global energy markets have negatively impacted, and are expected to continue to negatively impact, cash flows from operating activities. In order to mitigate these effects, we have implemented certain cost cutting measures, such as suspending our onshore drilling program for the remainder of 2020.
On June 24, 2020, we entered into an Open Market Sale Agreement with Jefferies LLC. Pursuant to the terms of the agreement, we may sell from time to time shares of our Common Stock having an aggregate offering price of up to $100,000,000. We intend to use the net proceeds from the offering to repay borrowings under our Credit Agreement and for general corporate purposes. Under the Open Market Sale Agreement, we sold 155,029 shares during the three months ended June 30, 2020 for net proceeds of $0.5 million.
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Cash From Operating Activities
Cash flows used inprovided by operating activities were approximately $0.2$8.2 million for the threesix months ended March 31,June 30, 2020 compared to $0.1$14.9 million used inprovided by operating activities for the same period in 2019. Included in the 2020 activity is $7.1 million in a deposit related to an escrow account set up for the drilling of the exploratory Iron Flea offshore well, which will be reclassed to expense in the second quarter of 2020 due to the well being unsuccessful. The table below provides additional detail of cash flows from operating activities for the threesix months ended March 31,June 30, 2020 and 2019:
| | | | | | | | | | | | |
| | Three Months Ended March 31, | | Six Months Ended June 30, | ||||||||
|
| 2020 |
| 2019 |
| 2020 |
| 2019 | ||||
| | (in thousands) | | (in thousands) | ||||||||
Cash flows from operating activities, exclusive of changes in working capital accounts | | $ | 12,300 | | $ | 4,525 | | $ | 17,663 | | $ | 5,902 |
Changes in operating assets and liabilities | | | (12,548) | | | (4,664) | | | (9,450) | | | 8,996 |
Net cash used in operating activities | | $ | (248) | | $ | (139) | | $ | 8,213 | | $ | 14,898 |
Cash From Investing Activities
Net cash flows used in investing activities were $9.5$19.5 million for the threesix months ended March 31,June 30, 2020, substantially all of which was primarily related to cash capital costs for leaseholdthe offshore exploratory prospect and drillingcompletion and infrastructure costs in the Southern Delaware Basin.
Net cash flows used in investing activities were $5.1$14.6 million for the threesix months ended March 31,June 30, 2019, substantially all of which was related to cash capital costs for leasehold and drilling and completion costs of wells in the Southern Delaware Basin and non-operated wells in the Georgetown formation.formation in Dimmitt County, Texas.
Cash From Financing Activities
Cash flows provided by financing activities for the threesix months ended March 31,June 30, 2020 were approximately $9.8$10.0 million primarilywith $6.4 million related to net borrowings outstanding under our Credit Agreement (as defined below)., and approximately $3.4 million related to proceeds from the PPP loan we received under the CARES Act in April 2020. See “Paycheck Protection Program Loan” below for more information. Cash flows provided byused in financing activities for the threesix months ended March 31,June 30, 2019 were approximately $5.3$0.3 million, primarily related to net borrowings outstanding under our Credit Agreement.shares withheld from employees for the payment of taxes due on vested shares of restricted stock issued.
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Credit Agreement
On September 17, 2019, we entered into a new revolving credit agreement with JPMorgan Chase Bank (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star property acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base was $145 million as of March 31, 2020. The borrowing base is subject to semi-annual redeterminations and may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The semi-annual redeterminations will occur on or around May 1st and November 1st of each year. On June 9, 2020, we entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million pursuant to the regularly scheduled redetermination process, which was in excess of borrowings outstanding. The Second Amendment also provides for, among other things, further $10 million automatic reductions in our borrowing base on each of June 30, 2020 and September 30, 2020. Accordingly, the borrowing base was $85 million as of June 30, 2020. Should borrowings outstanding exceed the reduced borrowing base on the dates of those stepdowns in the borrowing base, we would need to repay any excess within a short period of time through additional sources of liquidity, such as monetization of a portion of our hedge portfolio or the debt or equity capital markets, as available. Although the Company doeswe do not expect to have borrowings in excess of the reduced borrowing basesbase on each of June 30 and September 30, 2020, there can be no assurance that such sources of capital will be available to us. Please read Part II, Item 1A, “Risk Factors.” The Credit Agreement matures on September 17, 2024. As of March 31,June 30, 2020, the borrowing outstanding under the Credit Agreement was $79.1 million and $1.9 million in an outstanding letter of credit, and the borrowing availability under the Credit Agreement was $60.4 million..$4.0 million.
The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment provides for, among other things, the increase in the Applicable Margin grid on borrowings outstanding by 50 basis points, the implementation of an accounts payable aging reporting
39
covenant, and the implementation of typical anti-cash hoarding provisions and a cash sweep requirement, in certain circumstances, with respect to a consolidated cash balance in excess of $5.0 million. As of March 31,June 30, 2020, we were in compliance with all financial covenants under the Credit Agreement.
Paycheck Protection Program Loan
On April 10, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the CARES Act and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A and is included in “Long Term Debt” on our consolidated balance sheet.
The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. We may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.
Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: 1) the eight-week period beginning on the funding date; or 2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. We intend to use the PPP Loan amount for qualifying expenses and expect to apply for forgiveness of all or part of the PPP Loan in accordance with the terms of the CARES Act and applicable guidance. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to outstanding principal.
Application of Critical Accounting Policies and Management’s Estimates
Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our 2019 Form 10-K.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements, see Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies.”
Off Balance Sheet Arrangements
We may enter into off balance sheet arrangements that can give rise to off-balance sheet obligations. As of March 31,June 30, 2020, our off balance sheet arrangements consist of delay rentals, surface damage payments and rental payments associated with salt water disposal contracts, as discussed in our 2019 Form 10-K.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
As a “smaller reporting company”, we are not required to provide the information required by this Item.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
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Our management, with the participation of our President and Chief Executive Officer and our Chief Financial and Accounting Officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31,June 30, 2020. Based upon that evaluation, our President and Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of March 31,June 30, 2020, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer and our Chief Financial and Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
The Company is in the processfinal stages of integratingcompleting the integration of the accounting for the operating results of the assets of Will Energy’sEnergy and White Star’sStar into the Company’s internal controlscontrol structure over financial reporting.reporting, and in conjunction with that process, and where deemed appropriate or necessary, has incorporated controls similar to Company controls currently existing. As a result of these integration activities, certain controls will behave been evaluated and may be changed.revised where deemed appropriate. There was no change in our internal control over financial reporting during the fiscal quarterthree months ended March 31,June 30, 2020 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
For a discussion of legal proceedings, see Item 1. Note 1112 to our Financial Statements – “Commitments and Contingencies.”
Except as set forth below, thereThere have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our 2019 Form 10-K.10-K and Item 1A. of Part II of our Quarterly Report on Form 10-Q for the period ended March 31, 2020.
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our business, financial position, results of operations, and/or cash flows will depend on future developments, which are highly uncertain and cannot be predicted.
The COVID-19 pandemic and the actions by governments, businesses, and individuals in response to the pandemic have caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting our cash flow, liquidity and financial position. These events have worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. While OPEC+ reached a tentative agreement to cut oil production in April 2020, the announcement of the tentative agreement did not result in increased commodity prices, and those production cuts, if effected, may not offset near-term demand loss attributable to the COVID-19 pandemic and the related economic slowdown. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when, or to what extent, oil prices will improve and stabilize.
The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand, the availability of personnel, equipment, and services critical to our ability to operate our properties, and how quickly, and to what extent, normal economic and operating conditions can resume. The COVID-19 pandemic may also precipitate or intensify the risks described in the risk factors disclosed in our 2019 Form 10-K.
The reduction in the borrowing base under our Credit Agreement, and any further reductions as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
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Our primary sources of liquidity are borrowings under our Credit Agreement and cash from operations. The borrowing base under our Credit Agreement is subject to semi-annual redeterminations which occur on May 1st and November 1st of each year. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Agreement. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan, many of which factors are beyond our control. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment reduced the borrowing base from $145 million to $95 million pursuant to the regularly scheduled redetermination process and provided for further $10 million automatic borrowing base reductions on each of June 30, 2020 and September 30, 2020. As a result of these reductions, we expect to have limited availability under our Credit Agreement, which will impact our readily available access to financing for our capital expenditures.
Should a determination be made to lower the borrowing base to a level less than our outstanding indebtedness thereunder on the date of such reduction, the excess indebtedness (i.e a “deficiency”) would exist that the Company would be required to repay, depending on certain scenarios, either immediately or over a period of six months. Should such a determination be made that creates a deficiency, we may be required to obtain additional capital from monetizing hedges or accessing the capital markets. There is no assurance, however, that we will be able to do so on acceptable terms, if at all. If we are unable to obtain new capital on acceptable terms, we may be unable to operate our producing properties, recommence or implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The Company withheld the following shares from employees during the quarter ended March 31,June 30, 2020 for the payment of taxes due on shares of restricted stock that vested and were issued under its stock-based compensation plans:
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Total Number of Shares | | | Approximate Dollar Value | | | | | | | | Total Number of Shares | | | Approximate Dollar Value | |
| | Total Number of | | Average Price | | Purchased as Part of | | | of Shares that May Yet | | | Total Number of | | Average Price | | Purchased as Part of | | | of Shares that May Yet | | ||
Period |
| Shares Withheld |
| Per Share |
| Publicly Announced Program |
| | be Purchased Under Program |
|
| Shares Withheld |
| Per Share |
| Publicly Announced Program |
| | be Purchased Under Program |
| ||
| | | | | | | | | | | | | | | | | | | | | | |
January 2020 | | 22,972 | | $ | 3.63 | | — | | $ | — | | |||||||||||
February 2020 | | — | | $ | — | | — | | $ | — | | |||||||||||
March 2020 | | 26,502 | | $ | 2.77 | | — | | $ | — | | |||||||||||
April 2020 | | 12,498 | | $ | 1.63 | | — | | $ | — | | |||||||||||
May 2020 | | 1,310 | | $ | 1.91 | | — | | $ | — | | |||||||||||
June 2020 | | — | | $ | — | | — | | $ | — | | |||||||||||
Total | | 49,474 | | $ | 3.17 | | — | | $ | 31.8 million (1) | | | 13,808 | | $ | 1.65 | | — | | $ | 31.8 million (1) | |
| | | | | | | | | | | | |||||||||||
| | | | | | | | | | | |
(1) | In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. The program does not have an expiration date. No shares were purchased for the quarter ended |
Item 3. Defaults upon Senior Securities
None.
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Exhibit |
| Description |
3.1 | | |
3.2 | | |
3.3 | | |
10.1 | | |
10.2 | | |
31.1 | ||
31.2 | ||
32.1 | ||
32.2 | ||
101 | Interactive Data Files † |
† | Filed herewith. |
* Furnished herewith.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | |
| | | CONTANGO OIL & GAS COMPANY |
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| | | |
Date: | By: | | /s/ WILKIE S. COLYER |
| | | Wilkie S. Colyer |
| | |
|
| | | (Principal Executive Officer) |
| | | |
| | | |
Date: | By: | | /s/ E. JOSEPH GRADY |
| | | E. Joseph Grady |
| | | Senior Vice President and Chief Financial and Accounting Officer |
| | | (Principal Financial and Accounting Officer) |
| | | |
| | | |
| | | |
| | | |
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