UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 20182019
Commission File Number 1-8754
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware (State of Incorporation) | 20-3940661 (I.R.S. Employer Identification No.) |
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575 North Dairy Ashford, Suite 1200 Houston, Texas 77079 (281) 874-2700 (Address and telephone number of principal executive offices) Securities registered pursuant to Section 12(b) of the Act: |
Securities registered pursuant to Section 12(b) of the Act:
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| | |
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Stock, par value $0.01 per share | SBOW | New York Stock Exchange |
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.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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 definition 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 | o | | Accelerated Filer | þ | | Non-Accelerated Filer | o | | Smaller Reporting Company | oþ |
Emerging Growth Company | o | | | | | | | | | |
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 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).
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d)of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Indicate the number of shares outstanding of each of the issuer’s classes
of common stock, as of the latest practicable date.
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Common Stock ($.01 Par Value) (Class of Stock) | 11,667,16511,758,317 Shares outstanding at August 1, 20182019 |
Explanatory Note
On May 5, 2017, through an amendment to its Certificate of Incorporation and Bylaws, Swift Energy Company changed its name to SilverBow Resources, Inc. Additionally, SilverBow Resources, Inc. began trading on the New York Stock Exchange ("NYSE") under the symbol "SBOW" on May 5, 2017.
SILVERBOW RESOURCES, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 20182019
INDEX
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Part I | FINANCIAL INFORMATION | |
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Item 1. | Condensed Consolidated Financial Statements | |
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Item 2. | | |
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Item 3. | | |
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Item 4. | | |
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Part II | OTHER INFORMATION | |
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Item 1. | | |
Item 1A. | | |
Item 2. | | |
Item 3. | | |
Item 4. | | |
Item 5. | | |
Item 6. | | |
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PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)
| | | June 30, 2018 |
| December 31, 2017 | | | | | |
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|
| June 30, 2019 |
| December 31, 2018 |
ASSETS | |
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Current Assets: | |
| | |
| |
Cash and cash equivalents | $ | 6,611 |
|
| $ | 7,806 |
| $ | 3,333 |
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| $ | 2,465 |
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Accounts receivable, net | 22,057 |
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| 27,263 |
| 34,760 |
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| 46,472 |
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Fair value of commodity derivatives | 1,775 |
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| 5,148 |
| 21,738 |
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| 15,261 |
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Other current assets | 3,090 |
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| 2,352 |
| 3,241 |
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| 2,126 |
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Total Current Assets | 33,533 |
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| 42,569 |
| 63,072 |
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| 66,324 |
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Property and Equipment: | |
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| |
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| |
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Property and Equipment, full cost method, including $53,865 and $50,377 of unproved property costs not being amortized at the end of each period | 796,052 |
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| 712,166 |
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Property and equipment, full cost method, including $49,866 and $56,715, respectively, of unproved property costs not being amortized at the end of each period | | 1,144,217 |
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| 986,100 |
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Less – Accumulated depreciation, depletion, amortization & impairment | (242,997 | ) |
| (216,769 | ) | (330,638 | ) |
| (284,804 | ) |
Property and Equipment, Net | 553,055 |
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| 495,397 |
| 813,579 |
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| 701,296 |
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Fair value of long-term commodity derivatives | 3,332 |
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| 2,553 |
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Right of Use Assets | | 12,568 |
| | — |
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Fair Value of Long-Term Commodity Derivatives | | 5,910 |
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| 4,333 |
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Deferred Tax Asset | | 21,164 |
| | — |
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Other Long-Term Assets | 7,076 |
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| 10,751 |
| 4,895 |
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| 5,567 |
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Total Assets | $ | 596,996 |
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| $ | 551,270 |
| $ | 921,188 |
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| $ | 777,520 |
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LIABILITIES AND STOCKHOLDERS’ EQUITY | |
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Current Liabilities: | |
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Accounts payable and accrued liabilities | $ | 35,350 |
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| $ | 44,437 |
| $ | 33,320 |
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| $ | 48,921 |
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Fair value of commodity derivatives | 11,742 |
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| 5,075 |
| 2,035 |
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| 2,824 |
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Accrued capital costs | 41,821 |
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| 10,883 |
| 28,166 |
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| 38,073 |
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Accrued interest | 2,597 |
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| 2,106 |
| 1,333 |
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| 1,513 |
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Current lease liability | | 7,006 |
| | — |
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Undistributed oil and gas revenues | 10,953 |
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| 12,996 |
| 11,755 |
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| 14,681 |
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Total Current Liabilities | 102,463 |
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| 75,497 |
| 83,615 |
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| 106,012 |
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| Long-Term Debt, net | 274,577 |
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| 265,325 |
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Long-Term Debt, Net | | 466,433 |
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| 387,988 |
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Non-Current Lease Liability | | 5,605 |
| | — |
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Deferred Tax Liabilities | 328 |
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| — |
| 1,446 |
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| 1,014 |
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Asset Retirement Obligations | 4,258 |
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| 8,678 |
| 4,218 |
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| 3,956 |
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Fair value of long-term commodity derivatives | 5,427 |
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| 2,758 |
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Other Long-Term Liabilities | 2,500 |
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| 5,554 |
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Fair Value of Long-Term Commodity Derivatives | | 987 |
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| 3,723 |
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Commitments and Contingencies (Note 11) |
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Stockholders' Equity: | |
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Preferred stock, $.01 par value, 10,000,000 shares authorized, none issued | — |
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| — |
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Common stock, $.01 par value, 40,000,000 shares authorized, 11,733,036 and 11,621,385 shares issued and 11,667,165 and 11,570,621 shares outstanding, respectively | 117 |
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| 116 |
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Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued | | — |
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| — |
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Common stock, $0.01 par value, 40,000,000 shares authorized, 11,838,397 and 11,757,972 shares issued, respectively, and 11,757,573 and 11,692,101 shares outstanding, respectively | | 118 |
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| 118 |
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Additional paid-in capital | 282,726 |
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| 279,111 |
| 289,899 |
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| 286,281 |
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Treasury stock, held at cost, 65,871 and 50,764 shares | (1,870 | ) |
| (1,452 | ) | |
Retained earnings (Accumulated deficit) | (73,530 | ) |
| (84,317 | ) | |
Treasury stock, held at cost, 80,824 and 65,871 shares, respectively | | (2,188 | ) |
| (1,870 | ) |
Retained earnings (accumulated deficit) | | 71,055 |
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| (9,702 | ) |
Total Stockholders’ Equity | 207,443 |
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| 193,458 |
| 358,884 |
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| 274,827 |
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Total Liabilities and Stockholders’ Equity | $ | 596,996 |
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| $ | 551,270 |
| $ | 921,188 |
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| $ | 777,520 |
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| See accompanying Notes to Condensed Consolidated Financial Statements. |
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except per-share amounts)
| | | Three Months Ended June 30, 2018 |
| Three Months Ended June 30, 2017 | Three Months Ended June 30, 2019 |
| Three Months Ended June 30, 2018 |
Revenues: | |
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Oil and gas sales | $ | 51,347 |
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| $ | 45,782 |
| $ | 74,703 |
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| $ | 51,347 |
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| Operating Expenses: | |
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General and administrative, net | 5,794 |
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| 6,811 |
| 6,624 |
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| 5,794 |
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Depreciation, depletion, and amortization | 13,096 |
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| 10,828 |
| 24,029 |
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| 13,096 |
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Accretion of asset retirement obligations | 84 |
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| 576 |
| 86 |
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| 84 |
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Lease operating costs | 3,760 |
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| 4,776 |
| 5,035 |
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| 3,760 |
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Workovers | | (127 | ) | | — |
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Transportation and gas processing | 5,421 |
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| 4,761 |
| 6,728 |
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| 5,421 |
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Severance and other taxes | 2,662 |
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| 2,280 |
| 3,950 |
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| 2,662 |
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Total Operating Expenses | 30,817 |
| | 30,032 |
| 46,325 |
| | 30,817 |
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| Operating Income (Loss) | 20,530 |
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| 15,750 |
| 28,378 |
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| 20,530 |
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| Non-Operating Income (Expense) |
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Gain (loss) on commodity derivatives, net | (10,752 | ) |
| 5,132 |
| 24,925 |
|
| (10,752 | ) |
Interest expense, net | (6,585 | ) |
| (4,642 | ) | (9,306 | ) |
| (6,585 | ) |
Other income (expense), net | (546 | ) |
| 1 |
| (28 | ) |
| (546 | ) |
| Income (Loss) Before Income Taxes | 2,647 |
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| 16,241 |
| 43,969 |
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| 2,647 |
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| Provision (Benefit) for Income Taxes | 328 |
|
| — |
| (20,735 | ) |
| 328 |
|
| Net Income (Loss) | $ | 2,319 |
|
| $ | 16,241 |
| $ | 64,704 |
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| $ | 2,319 |
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| Per Share Amounts- | |
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Per Share Amounts | | |
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| Basic: Net Income (Loss) | $ | 0.20 |
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| $ | 1.41 |
| $ | 5.51 |
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| $ | 0.20 |
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| Diluted: Net Income (Loss) | $ | 0.20 |
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| $ | 1.41 |
| $ | 5.49 |
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| $ | 0.20 |
|
| Weighted Average Shares Outstanding - Basic | 11,655 |
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| 11,487 |
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Weighted-Average Shares Outstanding - Basic | | 11,746 |
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| 11,655 |
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| Weighted Average Shares Outstanding - Diluted | 11,757 |
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| 11,554 |
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Weighted-Average Shares Outstanding - Diluted | | 11,780 |
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| 11,757 |
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| See accompanying Notes to Condensed Consolidated Financial Statements. |
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| Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
Revenues: | | | |
Oil and gas sales | $ | 146,768 |
| | $ | 104,099 |
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| | | |
Operating Expenses: | |
| | |
General and administrative, net | 12,900 |
| | 11,370 |
|
Depreciation, depletion, and amortization | 45,834 |
| | 26,228 |
|
Accretion of asset retirement obligations | 168 |
| | 243 |
|
Lease operating costs | 9,567 |
| | 8,721 |
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Workovers | 519 |
| | — |
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Transportation and gas processing | 13,135 |
| | 10,446 |
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Severance and other taxes | 7,266 |
| | 5,692 |
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Total Operating Expenses | 89,389 |
| | 62,700 |
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Operating Income (Loss) | 57,379 |
| | 41,399 |
|
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Non-Operating Income (Expense) | | | |
Gain (loss) on commodity derivatives, net | 20,903 |
| | (17,107 | ) |
Interest expense, net | (18,065 | ) | | (12,474 | ) |
Other income (expense), net | 37 |
| | (703 | ) |
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Income (Loss) Before Income Taxes | 60,254 |
| | 11,115 |
|
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Provision (Benefit) for Income Taxes | (20,503 | ) | | 328 |
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Net Income (Loss) | $ | 80,757 |
| | $ | 10,787 |
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Per Share Amounts | |
| | |
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Basic: Net Income (Loss) | $ | 6.89 |
| | $ | 0.93 |
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| | | |
Diluted: Net Income (Loss) | $ | 6.85 |
| | $ | 0.92 |
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| | | |
Weighted-Average Shares Outstanding - Basic | 11,727 |
| | 11,629 |
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| | | |
Weighted-Average Shares Outstanding - Diluted | 11,786 |
| | 11,742 |
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| | | |
See accompanying Notes to Condensed Consolidated Financial Statements. | | | |
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except per-share amounts)
|
| | | | | | | |
| Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2017 |
Revenues: | | | |
Oil and gas sales | $ | 104,099 |
| | $ | 88,194 |
|
| | | |
Operating Expenses: | | | |
General and administrative, net | 11,370 |
| | 16,645 |
|
Depreciation, depletion, and amortization | 26,228 |
| | 20,543 |
|
Accretion of asset retirement obligations | 243 |
| | 1,140 |
|
Lease operating costs | 8,721 |
| | 10,549 |
|
Transportation and gas processing | 10,446 |
| | 9,146 |
|
Severance and other taxes | 5,692 |
| | 3,898 |
|
Total Operating Expenses | 62,700 |
| | 61,921 |
|
| | | |
Operating Income (Loss) | 41,399 |
| | 26,273 |
|
| | | |
Non-Operating Income (Expense) | | | |
Gain (loss) on commodity derivatives, net | (17,107 | ) | | 16,068 |
|
Interest expense, net | (12,474 | ) | | (8,249 | ) |
Other income (expense), net | (703 | ) | | (141 | ) |
| | | |
Income (Loss) Before Income Taxes | 11,115 |
| | 33,951 |
|
| | | |
Provision (Benefit) for Income Taxes | 328 |
| | — |
|
| | | |
Net Income (Loss) | $ | 10,787 |
| | $ | 33,951 |
|
| | | |
Per Share Amounts- | |
| | |
| | | |
Basic: Net Income (Loss) | $ | 0.93 |
| | $ | 2.99 |
|
| | | |
Diluted: Net Income (Loss) | $ | 0.92 |
| | $ | 2.97 |
|
| | | |
Weighted Average Shares Outstanding - Basic | 11,629 |
| | 11,360 |
|
| | | |
Weighted Average Shares Outstanding - Diluted | 11,742 |
| | 11,445 |
|
| | | |
See accompanying Notes to Condensed Consolidated Financial Statements. | | | |
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands, except share amounts)
| | | Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Retained Earnings (Accumulated Deficit) | | Total | Common Stock | | Additional Paid-In Capital | | Treasury Stock | | Retained Earnings (Accumulated Deficit) | | Total |
Balance, December 31, 2016 | $ | 101 |
| | $ | 232,917 |
| | $ | (675 | ) | | $ | (156,288 | ) | | $ | 76,055 |
| |
| | | | | | | | | | |
Purchase of treasury shares (28,279 shares) | — |
| | — |
| | (777 | ) | | — |
| | (777 | ) | |
Issuance common stock (1,403,508 shares) | 14 |
| | 39,166 |
| | — |
| | — |
| | 39,180 |
| |
Issuance of restricted stock (141,818 shares) | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| |
Share-based compensation | — |
| | 7,029 |
| | — |
| | — |
| | 7,029 |
| |
Net Income | — |
| | — |
| | — |
| | 71,971 |
| | 71,971 |
| |
Balance, December 31, 2017 | $ | 116 |
| | $ | 279,111 |
| | $ | (1,452 | ) | | $ | (84,317 | ) | | $ | 193,458 |
| $ | 116 |
| | $ | 279,111 |
| | $ | (1,452 | ) | | $ | (84,317 | ) | | $ | 193,458 |
|
| | | | | | | | | | | | | | | | | | |
Shares issued from option exercise (29,199 shares) | — |
| | 708 |
| | — |
| | — |
| | 708 |
| — |
| | 708 |
| | — |
| | — |
| | 708 |
|
Purchase of treasury shares (15,107 shares) | — |
| | — |
| | (418 | ) | | — |
| | (418 | ) | |
Issuance of restricted stock (82,452 shares) | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| |
Purchase of treasury shares (10,458 shares) | | — |
| | — |
| | (290 | ) | | — |
| | (290 | ) |
Issuance of restricted stock (63,275 shares) | | 1 |
| | (1 | ) | | — |
| | — |
| | — |
|
Share-based compensation | | — |
| | 1,485 |
| | — |
| | — |
| | 1,485 |
|
Net Income | | — |
| | — |
| | — |
| | 8,466 |
| | 8,466 |
|
Balance, March 31, 2018 | | $ | 117 |
| | $ | 281,303 |
| | $ | (1,742 | ) | | $ | (75,851 | ) | | $ | 203,827 |
|
| | | | | | | | | | |
Purchase of treasury shares (4,649 shares) | | — |
| | — |
| | (128 | ) | | — |
| | (128 | ) |
Issuance of restricted stock (19,177 shares) | | — |
| | — |
| | — |
| | — |
| | — |
|
Share-based compensation | — |
| | 2,908 |
| | — |
| | — |
| | 2,908 |
| — |
| | 1,423 |
| | — |
| | — |
| | 1,423 |
|
Net Income | — |
| | — |
| | — |
| | 10,787 |
| | 10,787 |
| — |
| | — |
| | — |
| | 2,319 |
| | 2,319 |
|
Balance, June 30, 2018 | $ | 117 |
| | $ | 282,726 |
| | $ | (1,870 | ) | | $ | (73,530 | ) | | $ | 207,443 |
| $ | 117 |
| | $ | 282,726 |
| | $ | (1,870 | ) | | $ | (73,532 | ) | | $ | 207,441 |
|
| | | | | | | | | | | | | | | | | | |
Balance, December 31, 2018 | | $ | 118 |
| | $ | 286,281 |
| | $ | (1,870 | ) | | $ | (9,702 | ) | | $ | 274,827 |
|
| | | | | | | | | | |
Purchase of treasury shares (11,076 shares) | | — |
| | — |
| | (260 | ) | | — |
| | (260 | ) |
Issuance of restricted stock (61,263 shares) | | — |
| | — |
| | — |
| | — |
| | — |
|
Share-based compensation | | — |
| | 1,849 |
| | — |
| | — |
| | 1,849 |
|
Net Income | | — |
| | — |
| | — |
| | 16,053 |
| | 16,053 |
|
Balance, March 31, 2019 | | $ | 118 |
| | $ | 288,130 |
| | $ | (2,130 | ) | | $ | 6,351 |
| | $ | 292,469 |
|
| | | | | | | | | | |
Purchase of treasury shares (3,877 shares) | | — |
| | — |
| | (58 | ) | | — |
| | (58 | ) |
Issuance of restricted stock (19,162 shares) | | — |
| | — |
| | — |
| | — |
| | — |
|
Share-based compensation | | — |
| | 1,769 |
| | — |
| | — |
| | 1,769 |
|
Net Income | | — |
| | — |
| | — |
| | 64,704 |
| | 64,704 |
|
Balance, June 30, 2019 | | $ | 118 |
| | $ | 289,899 |
| | $ | (2,188 | ) | | $ | 71,055 |
| | $ | 358,884 |
|
See accompanying Notes to Condensed Consolidated Financial Statements. |
Condensed Consolidated Statements of Cash Flows (Unaudited)
SilverBow Resources, Inc. and Subsidiaries (in thousands) | |
| Six Months Ended June 30, 2018 |
| Six Months Ended June 30, 2017 | Six Months Ended June 30, 2019 |
| Six Months Ended June 30, 2018 |
Cash Flows from Operating Activities: |
|
|
|
|
|
|
Net income (loss) | $ | 10,787 |
|
| $ | 33,951 |
| $ | 80,757 |
|
| $ | 10,787 |
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities |
|
|
|
|
|
|
Depreciation, depletion, and amortization | 26,228 |
|
| 20,543 |
| 45,834 |
|
| 26,228 |
|
Accretion of asset retirement obligations | 243 |
|
| 1,140 |
| 168 |
|
| 243 |
|
Deferred income taxes | 328 |
|
| — |
| (20,732 | ) |
| 328 |
|
Share-based compensation expense | 2,675 |
|
| 3,136 |
| 3,339 |
|
| 2,675 |
|
(Gain) Loss on derivatives, net | 17,107 |
|
| (16,068 | ) | (20,903 | ) |
| 17,107 |
|
Cash settlement (paid) received on derivatives | (1,935 | ) |
| (2,586 | ) | 4,381 |
|
| (1,935 | ) |
Settlements of asset retirement obligations | (144 | ) |
| (1,894 | ) | (47 | ) |
| (144 | ) |
Write down of debt issuance cost | — |
|
| 2,401 |
| |
Other | 3,374 |
|
| 482 |
| 1,160 |
|
| 3,374 |
|
Change in operating assets and liabilities- |
|
|
|
|
| |
Change in operating assets and liabilities | |
|
|
|
|
|
(Increase) decrease in accounts receivable and other current assets | 2,332 |
|
| (1,486 | ) | 13,411 |
|
| 2,332 |
|
Increase (decrease) in accounts payable and accrued liabilities | (8,439 | ) |
| 4,437 |
| (6,928 | ) |
| (8,439 | ) |
Increase (decrease) in accrued interest | 491 |
|
| (90 | ) | (180 | ) |
| 491 |
|
Net Cash Provided by (used in) Operating Activities | 53,047 |
|
| 43,966 |
| |
Net Cash Provided by (Used in) Operating Activities | | 100,260 |
|
| 53,047 |
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
Additions to property and equipment | (84,097 | ) |
| (85,655 | ) | (174,138 | ) |
| (84,097 | ) |
Proceeds from the sale of property and equipment | 26,924 |
|
| 460 |
| (96 | ) |
| 26,924 |
|
Payments on property sale obligations | (6,042 | ) |
| — |
| (2,840 | ) |
| (6,042 | ) |
Transfer of company funds from restricted cash | — |
|
| (15 | ) | |
Net Cash Provided by (Used in) Investing Activities | (63,215 | ) |
| (85,210 | ) | (177,074 | ) |
| (63,215 | ) |
Cash Flows from Financing Activities: |
|
|
|
|
|
|
Proceeds from bank borrowings | 122,300 |
|
| 300,000 |
| 227,000 |
|
| 122,300 |
|
Payments of bank borrowings | (113,300 | ) |
| (287,000 | ) | (149,000 | ) |
| (113,300 | ) |
Net proceeds from issuances of common stock | 708 |
|
| 39,244 |
| — |
|
| 708 |
|
Purchase of treasury shares | (418 | ) |
| (618 | ) | (318 | ) |
| (418 | ) |
Payments of debt issuance costs | (317 | ) |
| (4,073 | ) | — |
|
| (317 | ) |
Net Cash Provided by (Used in) Financing Activities | 8,973 |
|
| 47,553 |
| 77,682 |
|
| 8,973 |
|
| Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash | (1,195 | ) |
| 6,309 |
| |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | 868 |
|
| (1,195 | ) |
Cash, Cash Equivalents and Restricted Cash, at Beginning of Period | 8,026 |
|
| 497 |
| 2,465 |
|
| 8,026 |
|
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 6,831 |
|
| $ | 6,806 |
| $ | 3,333 |
|
| $ | 6,831 |
|
| Supplemental Disclosures of Cash Flow Information: | |
|
|
|
| |
|
|
|
|
Cash paid during period for interest, net of amounts capitalized | $ | 10,926 |
|
| $ | 8,847 |
| $ | 17,128 |
|
| $ | 10,926 |
|
Changes in capital accounts payable and capital accruals | $ | 35,299 |
|
| $ | 5,356 |
| $ | (16,521 | ) |
| $ | 35,299 |
|
Changes in other long-term liabilities for capital expenditures | $ | (2,500 | ) |
| $ | — |
| $ | — |
|
| $ | (2,500 | ) |
See accompanying Notes to Condensed Consolidated Financial Statements |
|
|
| |
See accompanying Notes to Condensed Consolidated Financial Statements. | |
|
|
|
Notes to Condensed Consolidated Financial Statements (Unaudited)
SilverBow Resources, Inc. and Subsidiaries
(1) General Information
SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is a growth orientedgrowth-oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.
The condensed consolidated financial statements included herein are unaudited and have been prepared by the Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 20172018, as filed with the Securities and Exchange Commission on March 1, 2018.February 28, 2019.
(2) Summary of Significant Accounting Policies
Basis of Presentation. The consolidated financial statements included herein have been prepared by SilverBow, and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly-owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. There were no material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows there-from, and the ceiling testCeiling Test impairment calculation,
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
estimates of future costs to develop and produce reserves,
accruals related to oil and gas sales, capital expenditures and lease operating expenses,
estimates in the calculation of share-based compensation expense,
estimates of our ownership in properties prior to final division of interest determination,
the estimated future cost and timing of asset retirement obligations,
estimates made in our income tax calculations,
estimates in the calculation of the fair value of commodity derivative assets and liabilities,
estimates in the assessment of current litigation claims against the Company, and
estimates in amounts due with respect to open state regulatory audits.audits, and
estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 20182019 and 2017,2018, such internal costs when capitalized totaled $1.0$1.3 million and $1.2$1.0 million, respectively. For the six months ended June 30, 20182019 and 2017,2018, such internal costs capitalized totaled $2.4$2.9 million and $2.1$2.4 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these condensed consolidated financial statementsNotes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
| | | June 30, 2018 | | December 31, 2017 | June 30, 2019 | | December 31, 2018 |
Property and Equipment | | | | | | |
Proved oil and gas properties | $ | 738,780 |
| | $ | 658,519 |
| $ | 1,090,496 |
| | $ | 925,865 |
|
Unproved oil and gas properties | 53,865 |
| | 50,377 |
| 49,866 |
| | 56,715 |
|
Furniture, fixtures, and other equipment | 3,407 |
| | 3,270 |
| |
Furniture, fixtures and other equipment | | 3,855 |
| | 3,520 |
|
Less – Accumulated depreciation, depletion, amortization & impairment | (242,997 | ) | | (216,769 | ) | (330,638 | ) | | (284,804 | ) |
Property and Equipment, Net | $ | 553,055 |
| | $ | 495,397 |
| $ | 813,579 |
|
| $ | 701,296 |
|
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties-includingproperties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-byproperties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas
industry conditions, economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no write-down for each of the three months ended June 30, 2018 and 2017 and the six months ended June 30, 20182019 and 2017.the three and six months ended June 30, 2018
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.
Revenue Recognition. The Company adopted the new revenue recognition standard for revenue from contracts from customers (ASC 606) effective January 1, 2018. See Note 3 in these condensed consolidated financial statements for further details.
Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 20182019 and December 31, 2017,2018, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable”receivable, net” balance on the accompanying condensed consolidated balance sheets.
At June 30, 2018,2019, our “Accounts receivable”receivable, net” balance included $17.4$25.5 million for oil and gas sales, $1.1$0.8 million due from joint interest owners, $0.8$4.1 million for severance tax credit receivables and $2.8$4.4 million for other receivables. At December 31, 2017,2018, our “Accounts receivable”receivable, net” balance included $20.1$36.9 million for oil and gas sales, $2.1$5.6 million due from joint interest owners, $2.1$2.4 million for severance tax credit receivables and $3.0$1.6 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 20182019 and 20172018 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.3 million and $1.1 million for the three months ended June 30, 2019 and 2018, and 2017$2.6 million and $2.2 million and $2.3 million for the six months ended June 30, 20182019 and 2017,2018, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.
Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2018,2019, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
The Company was in a net deferred tax asset position prior to valuation allowance considerations, at both June 30, 20182019 and June 30, 2017 for United States federal income taxes. Management hasDecember 31, 2018. In prior periods, management had determined that it iswas not more likely than not that the Company willwould realize future cash benefits from its remaining federal carryover items and, accordingly, has takenhad maintained a full valuation allowance to offset its deferred tax assets. Tax expense
associated with federal income taxes was fully offset by adjustmentsDuring the quarter ended June 30, 2019, the Company completed several operational initiatives that resulted in increased production, lower development costs and an expanded inventory of development prospects. The successful results attributable to these initiatives led to management's determination, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released $21.2 million of the valuation allowance. We recognized $0.3allowance, resulting in a net deferred tax benefit of $20.7 million and $20.5 million for deferred state income tax expense during the three and six months ended June 30, 2018. We did not recognize any deferred2019, respectively. The Company recognized state income tax expense duringof $0.3 million and $0.5
million for the three and six months ended June 30, 2017.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Act”).2019, respectively. The Act makes broad and complex changes to the U.S. tax code that includes, among other provisions, a permanent reductionCompany recognized $0.3 million of the U.S. federal corporate tax rate from 35% to 21% and a repeal of the alternative minimum tax regime, both effective January 1, 2018. Because of the Company’s net deferred tax asset and valuation allowance positions, these changes did not impactstate income tax expense for the three and six months ended June 30, 2018.
The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop. The Company’s deferred tax balances and offsetting valuation allowance should be considered provisional. The final application of the Act to the Company’s tax computations may result in further adjustments. Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Company has utilized in calculating the transition impacts. The Company expects make any adjustments, if necessary, related to the impacts of this legislation by the end of 2018.
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
|
| | | | | | | |
| June 30, 2018 | | December 31, 2017 |
Trade accounts payable | $ | 16,015 |
| | $ | 20,884 |
|
Accrued operating expenses | 2,316 |
| | 3,490 |
|
Accrued compensation costs | 2,945 |
| | 5,334 |
|
Asset retirement obligations – current portion | 303 |
| | 2,109 |
|
Accrued non-income based taxes | 5,137 |
| | 3,898 |
|
Accrued corporate and legal fees | 3,120 |
| | 2,784 |
|
Other payables | 5,514 |
| | 5,938 |
|
Total accounts payable and accrued liabilities | $ | 35,350 |
| | $ | 44,437 |
|
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of each of June 30, 2018 and December 31, 2017, these assets were approximately $0.2 million. These amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.
The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying condensed consolidated statement of cash flows and their corresponding balance sheet presentation (in thousands):
|
| | | | | | | | | | | |
| June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
Cash and cash equivalents | $ | 6,611 |
| | $ | 7,806 |
| | $ | 6,627 |
|
Long-term restricted cash (1) | 220 |
| | 220 |
| | 179 |
|
Total cash, cash equivalents and restricted cash | $ | 6,831 |
| | $ | 8,026 |
| | $ | 6,806 |
|
(1) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2018, we purchased 15,107 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
Fresh Start Accounting. Upon emergence from bankruptcy on April 22, 2016, the Company adopted Fresh Start Accounting. As a result of the application of fresh start accounting, as well as the effects of the implementation of the joint plan
of reorganization (the “Plan”), the Consolidated Financial Statements on or after April 22, 2016, are not comparable with the Consolidated Financial Statements prior to that date.
New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Updated (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.
At December 31, 2017 the Company’s total lease commitments were approximately $6.2 million. There have been no material changes to our previously disclosed lease commitment amounts. Of this total, $2.0 million is related to our corporate office sub-lease which has a remaining term of approximately three years. The remaining commitments are generally for equipment and vehicle leases, most of which are expiring during 2018. The Company did not enter into any significant additional lease obligations during the first six months of 2018 and is in the process of evaluating other contracts that may contain lease components that need to be recognized under this standard. Management plans to adopt ASU 2016-02 in the quarter ending March 31, 2019. Management continuously evaluates the economics of leasing versus purchase for operating equipment. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than the current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted.
In January 2017, the FASB issued ASU 2017-01, to assist entities in evaluating whether transactions should be accounted for as an acquisition or disposal of an asset or business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities are not a business. The guidance is effective for companies beginning January 1, 2018, with early adoption permitted. The Company has adopted this guidance as of January 1, 2018, and will apply it to any subsequent transactions.
(3) Revenue Recognition
Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605. The new standard includes a five-step revenue recognition model to follow to determine the timing and amounts to be recognized as revenues in an entity’s financial statements. We have modified our processes and controls to ensure our reported oil and gas sales revenue is determined in accordance with this standard. Adoption of this standard did not result in a different amount reported for oil and gas sales than what we would have reported under the previous standard. Accordingly, there was no cumulative effect adjustment required upon adoption.
Virtually all of our revenue reported as oil and gas sales in our condensed consolidated statements of operations is derived from contracts. No other material revenue sources are attributable to Revenue from Contracts within the scope of ASC 606.
Revenue from Contracts with CustomersRecognition
. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. The types of contracts vary between product streams as described below:
Sales Contracts for Unprocessed Gas
We deliver natural gas to midstream entities at field delivery meter stations, under either transportation or processing agreements. For unprocessed gas (delivered under transportation or gathering agreements), we retain title to the gas through the redelivery points into downstream pipelines. The purchasers take title and control at these redelivery points. Sales proceeds are determined using the gas delivered for each monthly period based on an agreed upon index. We record the monthly proceeds realized at the redelivery points as gas sales revenue, and record the fees paid to the mid-stream pipeline as transportation expense.
Contracts for Processed Gas and NGLs
NGLs are unique in that they remain in a gas state through normal field operations, and are typically part of the gas stream delivered to a gas processor. A gas processing facility is necessary to separate the NGLs from the gas. The most common NGL components are ethane, propane, butane, isobutane and pentane. Each of these NGL components has unique industrial and/or residential markets. Prices, which are typically quoted on a per gallon basis, can vary substantially between these products.
Where our raw gas contains commercially recoverable NGL components, we enter into agreements with midstream gas processors under which the processor takes delivery at meter stations in the field and transports the gas to its processing facility. The processing facility extracts the recoverable NGLs and the remaining natural gas (“residue gas”) is delivered to a downstream pipeline, while the processor typically takes control of and purchases the NGLs at the plant tailgate.
We either take delivery of (take in kind) the residue gas at the plant tailgate and sell it to third party purchasers, or we sell the residue gas to the processor. Sales to third parties are negotiated on a monthly, seasonal or term basis and are priced at applicable market indexes. When we sell to the processor, the sales price is determined using monthly index prices.
When we sell the NGLs to the processor, each NGL component has a separate index price. The processor’s statement segregates the individual component quantities and lists separate settlement amounts for each NGL component. The processor charges service or processing fees that are fixed in the processing agreement. We aggregate the revenue for all components and record NGL revenues as a single product.
Based on an analysis of the terms of our existing contracts, we determined that under substantially all of our processing agreements, we retain control of both the gas and NGLs through the processing facilities. As a result, the processor is both a service provider and a customer of the NGLs (and residue gas not sold to other parties) with the sales occurring at the plant outlet. Accordingly, we record gas and NGL sales at the value realized at the plant tailgate and record the processor’s fees as transportation and processing expense.
Contracts forOil sales
Under our oil sales contracts, we sell oil production at field delivery points at agreed-upon index pricing, adjusted for location differentials and product quality. Oil is priced on a per barrel basis. Oil is picked up by our purchasers’ trucks at our tank batteries. Control transfers when it is loaded on the purchasers’ trucks. We record oil revenue at the price received at the pick-up points.
Contract balances
Under our contracts we either invoice our customers on a monthly basis or receive monthly settlement statements from the purchasers. Invoices and settlement statements cover the products delivered during the calendar month. The performance obligation is deemed fully satisfied for each unit of product at the time control is transferred to the purchaser. Payment of each monthly settlement is unconditional. Accordingly, our product sales contracts do not give rise to any contract assets or liabilities connected to future performance obligations under ASC 606. Receivables for oil and gas sales are included in Accounts Receivable, net in the condensed consolidated balance sheets. See Note 2 above.
Settlements for performance obligations
We record revenue for the production delivered to the purchasers during each monthly accounting period. Settlements typically occur 30 - 60 days after the end of the delivery month. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals. Adjustments to prior period estimates were not material for the periods presented in our condensed consolidated statements of operations.
Transaction price allocated to remaining performance obligations
Our contract terms vary, with many being greater than one-year. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Product prices
under our long-term contracts (with delivery obligations greater than one month) are tied to indexes reflective of market value at the time of delivery.
Production imbalances
Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer available under ASC 606. To comply with the new standard, naturalNatural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. We do not have any material imbalances, so this change had no impact on our reported revenues.
Oil and Gas sales by product
The following table provides information regarding our oil and gas sales, by product, reported on the Statements of Operations for the three months ended June 30, 20182019 and 20172018 and the six months ended June 30, 20182019 and 20172018 (in thousands):
| | | | Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2017 | | Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2017 | | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 | | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
Oil, natural gas and NGLs sales: | | | | | | | | | | | | | | | | |
Oil | | $ | 9,638 |
| | $ | 6,527 |
| | $ | 21,078 |
| | $ | 13,728 |
| | $ | 24,940 |
| | $ | 9,638 |
| | $ | 39,547 |
| | $ | 21,078 |
|
Natural gas | | 36,369 |
| | 35,043 |
| | 72,136 |
| | 66,106 |
| | 43,587 |
| | 36,369 |
| | 94,874 |
| | 72,136 |
|
NGLs | | 5,339 |
| | 4,215 |
| | 10,900 |
| | 8,363 |
| | 6,166 |
| | 5,339 |
| | 12,319 |
| | 10,900 |
|
Other | | — |
| | (3 | ) | | (14 | ) | | (3 | ) | | 10 |
| | — |
| | 28 |
| | (14 | ) |
Total | | $ | 51,347 |
| | $ | 45,782 |
| | $ | 104,099 |
| | $ | 88,194 |
| | $ | 74,703 |
| | $ | 51,347 |
| | $ | 146,768 |
| | $ | 104,099 |
|
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
|
| | | | | | | |
| June 30, 2019 | | December 31, 2018 |
Trade accounts payable | $ | 18,560 |
| | $ | 32,683 |
|
Accrued operating expenses | 3,410 |
| | 3,549 |
|
Accrued compensation costs | 3,175 |
| | 4,785 |
|
Asset retirement obligations – current portion | 270 |
| | 302 |
|
Accrued non-income based taxes | 4,279 |
| | 3,583 |
|
Accrued corporate and legal fees | 239 |
| | 534 |
|
Other payables | 3,387 |
| | 3,485 |
|
Total accounts payable and accrued liabilities | $ | 33,320 |
| | $ | 48,921 |
|
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2019, we purchased 14,953 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this standard on January 1, 2019, using the modified retrospective transition approach. The Company has elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements upon adoption. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheet. We have elected to not account for lease and non-lease components separately.
As a result of the adoption, the Company's 2019 opening balances for right-of-use assets and lease liabilities was $2.2 million, attributable to operating leases. During the second quarter of 2019, the Company recorded additions to right of use assets of $11.5 million, primarily for equipment leases entered into during the second quarter of 2019. See Note 3 for more information.
(3) Leases
SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2019 all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheet. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):
|
| | | | | | | |
| Three Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets | | | |
Property, plant and equipment acquisitions - short-term leases | $ | 2,184 |
| | $ | 6,168 |
|
Property, plant and equipment acquisitions - operating leases | 11 |
| | 18 |
|
Total lease costs in property, plant and equipment additions | $ | 2,195 |
| | $ | 6,186 |
|
|
| | | | | | | |
| Three Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
Lease Costs Included in the Condensed Consolidated Statement of Operations | | | |
Lease operating costs - short-term leases | $ | 329 |
| | $ | 1,664 |
|
Lease operating costs - operating leases | 1,084 |
| | 1,138 |
|
General and administrative, net - operating leases | 175 |
| | 331 |
|
Total lease cost expensed | $ | 1,588 |
| | $ | 3,133 |
|
The lease term and the discount rate related to the Company's leases are as follows:
|
| | |
| As of June 30, 2019 |
Weighted-average remaining lease term (in years) | 2.1 |
|
Weighted-average discount rate | 5.0 | % |
As of June 30, 2019, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
|
| | | |
| June 30, 2019 |
2019 (remaining after June 30, 2019) | $ | 3,503 |
|
2020 | 7,091 |
|
2021 | 2,344 |
|
2022 | 40 |
|
2023 | 40 |
|
Thereafter | 348 |
|
Total undiscounted lease payments | $ | 13,366 |
|
Present value adjustment |
|
Net operating lease liabilities | $ | 13,366 |
|
Supplement cash flow information related to leases was as follows (in thousands):
|
| | | |
| Six Months Ended June 30, 2019 |
Cash paid for amounts included in the measurement of lease liabilities | |
Operating cash flows from operating leases | $ | 1,457 |
|
Investing cash flows from operating leases | $ | 18 |
|
(4) Share-Based Compensation
Share-Based Compensation Plans
Upon the Company's emergence from bankruptcy on April 22,In 2016, the Company's previous share-based compensation plans were canceled andCompany adopted the new 2016 Equity Incentive Plan was approved in accordance(as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the joint plan of reorganization.2016 Plan, the “Plans”) on December 15, 2016. Under the previous share-based compensation plan, the outstanding restricted stock awards and restricted stock unit awards for most employees vested on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled in April 2016
For awards granted after emergence from bankruptcy,Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.
The Company computes a deferred tax benefit for restricted stock awards unit awards(“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.3$1.6 million and $1.6$1.3 million for the three months ended June 30, 20182019 and 2017,2018, respectively, and $2.7$3.3 million and $3.1$2.7 million for the six months ended June 30, 20182019 and 2017,2018, respectively. Capitalized share-based compensation was $0.1 million for each of the three months ended June 30, 2019 and 2018, and 2017,$0.3 million and $0.2 million for each of the six months ended June 30, 2019 and 2018, and 2017.respectively.
We view stock option awards and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.
On April 2, 2019, our Board of Directors authorized a one-time grant of market-based awards (both RSUs and PSUs) in exchange for the cancellation of special equity awards (both RSUs and stock options) made to our named executive officers on August 9, 2018 (the “Equity Award Exchange”). As required under the terms of the 2016 Plan, this Equity Award Exchange was subject to shareholder approval. Pursuant to the Equity Award Exchange our executives were given the opportunity to exchange out-of-the-money or “underwater” stock options that were granted in August 2018 and certain RSUs also granted in August 2018 to receive a new equity award that consists of 50% time-based RSUs and 50% PSUs, granted under the 2016 Plan. The incremental compensation cost associated with the Equity Award Exchange was determined to be $1.2 million. This incremental cost was measured as the excess of the fair value of each new equity award, measured as of the date the new equity awards were granted,
over the fair value of the stock options and RSUs surrendered in exchange for the new equity awards, measured immediately prior to the cancellation. This incremental compensation cost is being recognized ratably over the vesting period or performance period, as applicable, of the new equity awards.
Stock Option Awards
The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes-MertonBlack-Scholes option pricing model to estimate the fair value of stock option awards.
At June 30, 2018,2019, we had $3.9$2.2 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2018:2019:
| | | Shares | | Wtd. Avg. Exer. Price | Shares | | Wtd. Avg. Exer. Price |
Options outstanding, beginning of period | 508,730 |
| | $ | 26.82 |
| 644,575 |
| | $ | 28.28 |
|
Options granted | — |
| | $ | — |
| |
Options forfeited | (21,319 | ) | | $ | 29.96 |
| (4,197 | ) | | $ | 27.00 |
|
Options canceled in Equity Award Exchange | | (201,406 | ) | | $ | 31.14 |
|
Options expired | (8,356 | ) | | $ | 26.96 |
| (68,987 | ) | | $ | 23.69 |
|
Options exercised | (29,199 | ) | | $ | 24.27 |
| |
Options outstanding, end of period | 449,856 |
| | $ | 26.98 |
| 369,985 |
| | $ | 27.59 |
|
Options exercisable, end of period | 141,347 |
| | $ | 25.84 |
| 130,601 |
| | $ | 28.42 |
|
Our outstanding stock option awards at June 30, 20182019 had $1.2 million ofno measurable aggregate intrinsic value. At June 30, 2018,2019, the weighted averageweighted-average remaining contract life of stock option awards outstanding was 6.66.5 years and exercisable was 3.65.0 years. The total intrinsic value of stock option awards exercisable had no value for the six months ended June 30, 2018 was $0.5 million.2019.
Restricted Stock Units
The 2016 equity incentive compensation plan allowsPlan and Inducement Plan allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).
As of June 30, 2018,2019, we had unrecognized compensation expense of $7.3$7.1 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.62.2 years.
The following table provides information regarding restricted stock unit award activity for the six months ended June 30, 2018:2019:
| | | Shares | | Grant Date Price | Shares | | Grant Date Price |
Restricted stock units outstanding, beginning of period | 346,740 |
| | $ | 26.99 |
| 340,678 |
| | $ | 27.64 |
|
Restricted stock units granted | 91,906 |
| | $ | 27.89 |
| 115,957 |
| | $ | 20.13 |
|
Restricted stock units granted under Equity Award Exchange | | 99,500 |
| | $ | 16.70 |
|
Restricted stock united canceled under Equity Award Exchange | | (24,622 | ) | | $ | 31.14 |
|
Restricted stock units forfeited | (21,011 | ) | | $ | 26.59 |
| (16,342 | ) | | $ | 26.81 |
|
Restricted stock units vested | (81,754 | ) | | $ | 25.04 |
| (80,425 | ) | | $ | 26.46 |
|
Restricted stock units outstanding, end of period | 335,881 |
| | $ | 27.74 |
| 434,746 |
| | $ | 23.14 |
|
Performance-Based Stock Units
On February 20, 2018, the Company granted 30,700 performance-based stock units for which the number of shares earned is based on the Total Shareholder Return ("TSR"total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers ("Peer Group") during the performance period from January 1, 2018 to December 31, 2020 ("Performance Period").2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date of valuation was $41.66 per unit or 150.61% as a percentage150.6% of the stock price with a remaining performance period of 2.7 years.price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo
simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years.
On May 21, 2019, the Company granted an additional 99,500 performance-based stock units (as part of the Equity Award Exchange discussed above) for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three years.
As of June 30, 2018,2019, we had unrecognized compensation expense of $1.1$3.5 million related to our performance-based stock units whichbased on the assumption of 100% target payout. The remaining weighted-average performance period is expected to be recognized over a period of three2.3 years. No shares vested during the six months ended June 30, 2018.2019.
(5) Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted averageweighted-average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended June 30, 20182019 and 20172018 and the six months ended June 30, 20182019 and 20172018 are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
| | | Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2017 | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 |
| Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount |
Basic EPS: | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) and Share Amounts | $ | 2,319 |
| | 11,655 |
| | $ | 0.20 |
| | $ | 16,241 |
| | 11,487 |
| | $ | 1.41 |
| $ | 64,704 |
| | 11,746 |
| | $ | 5.51 |
| | $ | 2,319 |
| | 11,655 |
| | $ | 0.20 |
|
Dilutive Securities: | | | | | | | | | | | | | | | | | | | | | | |
Restricted Stock Awards | | | — |
| | | | | | — |
| | | | | — |
| | | | | | — |
| | |
Restricted Stock Unit Awards | | | 16 |
| | | | | | 59 |
| | | | | 34 |
| | | | | | 16 |
| | |
Stock Option Awards | | | 86 |
| | | | | | 8 |
| | | | | — |
| | | | | | 86 |
| | |
Diluted EPS: | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) and Assumed Share Conversions | $ | 2,319 |
| | 11,757 |
| | $ | 0.20 |
| | $ | 16,241 |
| | 11,554 |
| | $ | 1.41 |
| $ | 64,704 |
| | 11,780 |
| | $ | 5.49 |
| | $ | 2,319 |
| | 11,757 |
| | $ | 0.20 |
|
| | | Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2017 | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
| Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount |
Basic EPS: | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) and Share Amounts | $ | 10,787 |
| | 11,629 |
| | $ | 0.93 |
| | $ | 33,951 |
| | 11,360 |
| | $ | 2.99 |
| $ | 80,757 |
| | 11,727 |
| | $ | 6.89 |
| | $ | 10,787 |
| | 11,629 |
| | $ | 0.93 |
|
Dilutive Securities: | | | | | | | | | | | | | | | | | | | | | | |
Restricted Stock Awards | | | — |
| | | | | | — |
| | | | | — |
| | | | | | — |
| | |
Restricted Stock Unit Awards | | | 17 |
| | | | | | 73 |
| | | | | 59 |
| | | | | | 17 |
| | |
Stock Option Awards | | | 96 |
| | | | | | 12 |
| | | | | — |
| | | | | | 96 |
| | |
Diluted EPS: | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) and Assumed Share Conversions | $ | 10,787 |
| | 11,742 |
| | $ | 0.92 |
| | $ | 33,951 |
| | 11,445 |
| | $ | 2.97 |
| $ | 80,757 |
| | 11,786 |
| | $ | 6.85 |
| | $ | 10,787 |
| | 11,742 |
| | $ | 0.92 |
|
Approximately 0.5 million and 0.4 million stock options to purchase shares were not included in the computation of Diluted EPS for each of the three months ended June 30, 2019 and 2018, respectively, and 20170.6 million and 0.4 million for the six months ended June 30, 2019 and 2018, and 2017respectively, because these stock options were antidilutive.
Less than 0.1Approximately 0.2 million and approximatelyless than 0.1 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for both the three months ended June 30, 20182019 and 20172018 because they were
antidilutive. There were less thanapproximately 0.1 million and approximatelyless than 0.1 million antidilutive shares of restricted stock units for both the six months ended June 30, 20182019 and 2017.2018.
LessApproximately 0.1 million and less than 0.1 million shares of performance-based restricted stock units were not included in the computation of Diluted EPS for the three and six months ended June 30, 2019, respectively, and less than 0.1 million shares of performance-based restricted stock units were not included for both the three and six months ended June 30, 2018 because they were antidilutive.
Approximately 4.32.1 million warrants to purchase common stock were not included in the computation of Diluted EPS for both the three months ended June 30, 2018 and 2017 and for the six months ended June 30, 20182019 and 20174.3 million warrants for both the three and six months ended June 30, 2018 because these warrants were antidilutive.
(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
| | | June 30, 2018 | | December 31, 2017 | June 30, 2019 | | December 31, 2018 |
Credit Facility Borrowings (1) | $ | 82,000 |
| | $ | 73,000 |
| $ | 273,000 |
| | $ | 195,000 |
|
Second Lien Notes due 2024 | 200,000 |
| | 200,000 |
| 200,000 |
| | 200,000 |
|
| 282,000 |
| | 273,000 |
| 473,000 |
| | 395,000 |
|
Unamortized discount on Second Lien Notes due 2024 | (1,889 | ) | | (1,992 | ) | (1,668 | ) | | (1,782 | ) |
Unamortized debt issuance cost on Second Lien Notes due 2024 | (5,534 | ) | | (5,683 | ) | (4,899 | ) | | (5,230 | ) |
Long-Term Debt, net | $ | 274,577 |
| | $ | 265,325 |
| $ | 466,433 |
| | $ | 387,988 |
|
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of each of June 30, 20182019 and December 31, 2017,2018, we had $4.9$3.8 million and $5.5$4.5 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $82.0$273.0 million and $73.0$195.0 million as of each of June 30, 20182019 and December 31, 2017,2018, respectively. On April 19, 2017, the Company entered into a First Amended and Restated Senior Secured Revolving Credit Agreement among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended, including the ThirdFourth Amendment, dated April 20,effective November 6, 2018 (the “Third“Fourth Amendment to Credit Agreement”), to the First Amended and Restated Senior Secured Credit Agreement (as so amended, the “Credit Agreement” and such facility, the “Credit Facility”). The ThirdFourth Amendment to Credit Agreement reaffirmedincreased the borrowing base atfrom $330 million to $410 million and decreased the applicable marginmargins used to calculate the interest rate under the Credit Agreement by 5025 basis points and carved out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Credit Agreement.points.
The Credit Facility matures April 19, 2022, and provides for a maximum credit amount of $600 million and a current borrowing base of $410 million. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reducereduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
Interest under the Credit Facility accrues at the Company’s option either at an Alternative Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). As of April 20,Since November 6, 2018, the
applicable margin rangesranged from 1.25%1.00% to 2.25%2.00% for ABR Loans and 2.25%2.00% to 3.25%3.00% for Eurodollar Loans. The Alternate Base Rate and LIBOR RatesRate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiaries.
The Credit Agreement contains the following financial covenants:
a ratio of total debt to EBITDA,earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 4.0 to 1.0 as of the last day of each fiscal quarter; and
a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.0 to 1.0 as of the last day of each fiscal quarter.
As of June 30, 2018,2019, the Company was in compliance with all financial covenants under the Credit Agreement. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replacedreplace produced reserves.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $1.6$4.0 million and $4.8$1.6 million for the three months ended June 30, 20182019 and 2017,2018, respectively, and $3.1$7.5 million and $8.5$3.1 million for the six months ended June 30, 20182019 and 2017, respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million and $0.1 million for the three months ended June 30, 2018, and 2017, respectively, and $0.6 million and $0.2 million for the six months ended June 30, 2018 and 2017, respectively.
We capitalized interest on our unproved properties in the amount $0.3of $0.1 million and $0.2$0.3 million for the three months ended June 30, 20182019 and 2017,2018, respectively and $0.7$0.2 million and $0.4$0.7 million for the six months ended June 30, 20182019 and 2017, respectively.2018.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a note purchase agreementNote Purchase Agreement for Senior Secured Second Lien Notes (the(as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, (the “Second Lien Agent”), and certain holders that are a party thereto, and issued notes in an initial principal amount of $200$200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100$100.0 million. The Second Lien matures on December 15, 2024. On April 20, 2018 the Company entered into a First Amendment (the “First Amendment to the Second Lien”) which carves out certain permitted basis differential swaps from the calculation of the maximum hedging covenant in the Note Purchase Agreement.
Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Second Lien. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to the following repayment fees: during years one and two, a customary “make-whole” amount (which is equal to the present value of the remaining interest payments through the twenty-four24 month anniversary of the issuance of the Second Lien, discounted at a rate equal to the U.S. Treasury Raterate plus 50 basis points) plus 2.0% of the principal amount of the notes repaid; during year three, 2.0% of the principal amount of the Second Lien being prepaid; during year four, 1.0% of the principal amount of the Second Lien being prepaid; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and
incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and certain of its subsidiaries, including a mortgage lien on oil and
gas properties attributed with at least 85% of estimated PV-9 of proved reserves of the Company and its subsidiaries and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the Administrative Agentadministrative agent of the Credit Facility.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiaries and in the denominator the total net indebtedness of the Company and its restricted subsidiaries, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio Requirement”Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt to EBITDA, as defined in the Second Lien purchase agreement,Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2018,2019, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien Facility to be immediately due and payable.
As of June 30, 2018,2019, total net amounts recorded for the Second Lien were $192.6$193.4 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.5 million and $10.8 million for the three and six months ended June 30, 2019, respectively, and $5.2 million and $10.0 million for the three and six months ended June 30, 2018.2018 respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.
(7) Acquisitions and Dispositions
On March 1, 2018, the Company closed the sale of certain wells in its AWP Olmos field for proceeds, net of selling expenses, of $27.0 million. This transaction hadmillion, with an effective date of January 1, 2018. The buyer assumed approximately $6.3 million in asset retirement obligations. No gain or loss was recorded on the sale of this property.
Effective December 22, 2017, the Company closed a Purchasepurchase and Salesale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.costs. Of the $16.3 million original obligation, $6.0$2.8 million was paid during the six months ended June 30, 2018. Additionally, we reclassified $2.5 million in other long-term liabilities related to this sale to current liabilities.2019. The remaining obligation under this contract is $10.2$4.6 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of June 30, 2018. This balance is made up of $7.7 million of current liability, which is included in “Accrued capital costs,” and $2.5 million, which is included in “Other Long-Term Liabilities.”2019.
There were no material acquisitions or dispositions of developed properties during the three and six months ended June 30, 2017.2019.
(8) Price-Risk Management Activities
Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in "Net gain“Gain (loss) on commodity derivatives"derivatives, net” on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainlyprimarily through the purchase of commodity price swaps and collars as well as basis swaps.
During the three months ended June 30, 20182019 and 2017,2018, the Company recorded gains of $25.0 million and losses of $10.8 million and gains of $5.1 million, respectively, on its commodity derivatives. During the six months ended June 30, 20182019 and 2017,2018, the Company recorded gains of $20.9 million and losses of $17.1 million and gains of $16.1 million, respectively, on its commodity derivatives. The Company collected cash payments of $4.4 million and made net cash
payments of $1.9 million and $2.6 million for settled derivative contracts during the six months ended June 30, 20182019 and 2017,2018, respectively.
At June 30, 2018 and2019, there were $3.6 million in receivables for settled derivatives while at December 31, 2017,2018 we had less than $0.1$0.7 million and $2.2 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 20182019 and January 2018,2019, respectively. At June 30, 20182019 and December 31, 2017,2018, we also had $1.6$0.2 million and $0.4$2.2 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in "Accounts“Accounts payable and accrued liabilities"liabilities” and were subsequently paid in July 20182019 and January 2018,2019, respectively.
The fair values of our derivativesswap contracts are computed using commonly accepted industry-standard modelsobservable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At June 30, 2018,2019, there was $1.8$21.7 million and $3.3$5.9 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $11.7$2.0 million and $5.4$1.0 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2017,2018, there was $5.1$15.3 million and $2.6$4.3 million in current and long-term unsettled derivative assets, respectively, and $5.1$2.8 million and $2.8$3.7 million in current and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry standardizedindustry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. Under the right of set-off, there was a $12.1$24.6 million net fair value liabilityasset at June 30, 20182019 and a $0.1$13.0 million net fair value liabilityasset at December 31, 2017.2018. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these condensed consolidated financial statements.Notes to Condensed Consolidated Financial Statements.
The following tables summarize the weighted averageweighted-average prices as well as future production volumes for our unsettledfuture derivative contracts in place as of June 30, 2018:2019:
| | Oil Derivative Swaps (NYMEX WTI Settlements) | Total Volumes (Bbls) | | Weighted Average Price | |
2018 Contracts | | | | |
3Q18 | 130,400 |
| | $ | 52.40 |
| |
4Q18 | 122,800 |
| | $ | 52.23 |
| |
| | | | |
Oil Derivative Swaps (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price |
2019 Contracts | | | | | | |
1Q19 | 107,700 |
| | $ | 52.77 |
| |
2Q19 | 103,200 |
| | $ | 52.72 |
| |
3Q19 | 99,000 |
| | $ | 52.79 |
| 314,500 |
| | $ | 60.41 |
|
4Q19 | 95,000 |
| | $ | 52.73 |
| 249,000 |
| | $ | 59.52 |
|
| | | | | | |
2020 Contracts | | | | | | |
1Q20 | 81,300 |
| | $ | 52.42 |
| 194,800 |
| | $ | 58.16 |
|
2Q20 | 77,850 |
| | $ | 52.38 |
| 191,350 |
| | $ | 58.32 |
|
3Q20 | 74,700 |
| | $ | 52.34 |
| 189,200 |
| | $ | 58.43 |
|
4Q20 | 72,000 |
| | $ | 52.29 |
| 118,000 |
| | $ | 55.65 |
|
| | | | |
2021 Contracts | | | | |
1Q21 | | 56,175 |
| | $ | 55.23 |
|
2Q21 | | 52,325 |
| | $ | 57.00 |
|
| | Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | Total Volumes (MMBtu) | | Weighted Average Price | Total Volumes (MMBtu) | | Weighted-Average Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price |
2018 Contracts | | | | |
3Q18 | 7,666,000 |
| | $ | 2.88 |
| |
4Q18 | 12,121,000 |
| | $ | 2.96 |
| |
| | | | |
2019 Contracts | | | | | | | | | | |
1Q19 | 7,516,000 |
| | $ | 3.08 |
| |
2Q19 | 6,060,000 |
| | $ | 2.83 |
| |
3Q19 | 5,550,000 |
| | $ | 2.84 |
| 12,680,000 |
| | $ | 2.81 |
| | | | |
4Q19 | 5,966,000 |
| | $ | 2.84 |
| 11,486,000 |
| | $ | 2.89 |
| | | | |
| | | | | | | | | | |
2020 Contracts | | | | | | | | | | |
1Q20 | 5,370,000 |
| | $ | 2.83 |
| 6,280,000 |
| | $ | 2.87 |
| | | | |
2Q20 | 3,688,000 |
| | $ | 2.76 |
| 3,688,000 |
| | $ | 2.76 |
| | | | |
3Q20 | 3,585,000 |
| | $ | 2.76 |
| 3,585,000 |
| | $ | 2.76 |
| | | | |
4Q20 | 3,362,000 |
| | $ | 2.77 |
| 3,362,000 |
| | $ | 2.77 |
| | | | |
| | | | | | | | |
Collar Contracts | | | | | | | | |
2021 Contracts | | | | | | | | |
1Q21 | | 4,354,800 |
| | | | $ | 2.50 |
| | $ | 3.52 |
|
2Q21 | | 3,791,000 |
| | | | $ | 2.20 |
| | $ | 2.75 |
|
|
| | | | | | |
NGL Contracts | Total Volumes (Bbls) | | Weighted Average Price |
2018 Contracts | | | |
3Q18 | 112,200 |
| | $ | 24.78 |
|
4Q18 | 148,200 |
| | $ | 24.78 |
|
|
| | | | | | |
NGL Contracts | Total Volumes (Bbls) | | Weighted-Average Price |
2019 Contracts | | | |
3Q19 | 180,000 |
| | $ | 27.93 |
|
4Q19 | 180,000 |
| | $ | 27.93 |
|
| | Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements) | Total Volumes (MMBtu) | | Weighted Average Price | |
2018 Contracts | | | | |
3Q18 | 7,595,000 |
| | $ | (0.01 | ) | |
4Q18 | 11,850,000 |
| | $ | (0.07 | ) | |
| | | | |
Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price |
2019 Contracts | | | | | | |
1Q19 | 11,310,000 |
| | $ | (0.08 | ) | |
2Q19 | 11,975,000 |
| | $ | 0.04 |
| |
3Q19 | 12,095,000 |
| | $ | 0.03 |
| 14,625,000 |
| | $ | 0.04 |
|
4Q19 | 12,095,000 |
| | $ | (0.04 | ) | 14,625,000 |
| | $ | (0.02 | ) |
| | | | | | |
2020 Contracts | | | | | | |
1Q20 | 1,820,000 |
| | $ | (0.10 | ) | 11,739,000 |
| | $ | (0.03 | ) |
2Q20 | 1,820,000 |
| | $ | (0.09 | ) | 11,739,000 |
| | $ | (0.04 | ) |
3Q20 | 1,840,000 |
| | $ | (0.07 | ) | 11,868,000 |
| | $ | (0.03 | ) |
4Q20 | 1,840,000 |
| | $ | (0.11 | ) | 11,868,000 |
| | $ | (0.04 | ) |
| | | | |
2021 Contracts | | | | |
1Q21 | | 7,200,000 |
| | $ | (0.003 | ) |
2Q21 | | 7,280,000 |
| | $ | (0.003 | ) |
3Q21 | | 7,360,000 |
| | $ | (0.003 | ) |
4Q21 | | 7,360,000 |
| | $ | (0.003 | ) |
|
| | | | | | |
Oil Basis Contracts | Total Volumes (Bbls) | | Weighted Average Price |
2018 Contracts | | | |
3Q18 | 80,000 |
| | $ | 4.13 |
|
4Q18 | 120,000 |
| | $ | 4.13 |
|
|
| | | | | | |
Oil Basis Contracts (Argus Cushing (WTI) and Louisiana Light Sweet Settlements) | Total Volumes (Bbls) | | Weighted-Average Price |
2019 Contracts | | | |
3Q19 | 75,000 |
| | $ | 3.73 |
|
4Q19 | 75,000 |
| | $ | 3.73 |
|
(9) Fair Value Measurements
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities,the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate fair value due to the highly liquid or short-term nature of these instruments.
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 20182019 and December 31, 2017,2018, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements.Notes to Condensed Consolidated Financial Statements.
| | | Fair Value Measurements at | Fair Value Measurements at |
(in millions) | Total | | Quoted Prices in Active markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | Total | | Quoted Prices in Active markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
June 30, 2018 | | | | | | | | |
June 30, 2019 | | | | | | | | |
Assets | | | | | | | | | | | | | | |
Natural Gas Derivatives | $ | 4.5 |
| | $ | — |
| | $ | 4.5 |
| | $ | — |
| |
Natural Gas Basis Derivatives | $ | 0.6 |
| | $ | — |
| | $ | 0.6 |
| | $ | — |
| |
Liabilities | | | | | | | | |
Natural Gas Derivatives | $ | 1.7 |
| | $ | — |
| | $ | 1.7 |
| | $ | — |
| $ | 13.9 |
| | $ | — |
| | $ | 13.9 |
| | $ | — |
|
Natural Gas Basis Derivatives | $ | 2.0 |
| | $ | — |
| | $ | 2.0 |
| | $ | — |
| $ | 5.8 |
| | $ | — |
| | $ | 5.8 |
| | $ | — |
|
Oil Derivatives | $ | 12.0 |
| | $ | — |
| | $ | 12.0 |
| | $ | — |
| $ | 4.4 |
| | $ | — |
| | $ | 4.4 |
| | $ | — |
|
Oil Basis Derivatives | $ | 0.2 |
| | $ | — |
| | $ | 0.2 |
| | $ | — |
| $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
|
NGL Derivatives | $ | 1.3 |
| | $ | — |
| | $ | 1.3 |
| | $ | — |
| $ | 3.4 |
| | $ | — |
| | $ | 3.4 |
| | $ | — |
|
December 31, 2017 | | | | | | | | |
Liabilities | | | | | | | | |
Natural Gas Derivatives | | $ | 0.3 |
| | $ | — |
| | $ | 0.3 |
| | $ | — |
|
Natural Gas Basis Derivatives | | $ | 0.6 |
| | $ | — |
| | $ | 0.6 |
| | $ | — |
|
Oil Derivatives | | $ | 2.1 |
| | $ | — |
| | $ | 2.1 |
| | $ | — |
|
December 31, 2018 | | | | | | | | |
Assets | | | | | | | | | | | | | | |
Natural Gas Derivatives | $ | 7.2 |
| | $ | — |
| | $ | 7.2 |
| | $ | — |
| $ | 7.5 |
| | $ | — |
| | $ | 7.5 |
| | $ | — |
|
Natural Gas Basis Derivatives | $ | 0.3 |
| | $ | — |
| | $ | 0.3 |
| | $ | — |
| $ | 0.4 |
| | $ | — |
| | $ | 0.4 |
| | $ | — |
|
Oil Derivatives | | $ | 6.9 |
| | $ | — |
| | $ | 6.9 |
| | $ | — |
|
NGL Derivatives | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
| $ | 4.7 |
| | $ | — |
| | $ | 4.7 |
| | $ | — |
|
Liabilities | | | | | | | | | | | | | | |
Natural Gas Derivatives | $ | 1.3 |
| | $ | — |
| | $ | 1.3 |
| | $ | — |
| $ | 1.0 |
| | $ | — |
| | $ | 1.0 |
| | $ | — |
|
Natural Gas Basis Derivatives | $ | 0.3 |
| | $ | — |
| | $ | 0.3 |
| | $ | — |
| $ | 5.3 |
| | $ | — |
| | $ | 5.3 |
| | $ | — |
|
Oil Derivatives | $ | 5.2 |
| | $ | — |
| | $ | 5.2 |
| | $ | — |
| |
Oil Basis Derivatives | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
| |
NGL Derivatives | $ | 0.9 |
| | $ | — |
| | $ | 0.9 |
| | $ | — |
| $ | 0.2 |
| | $ | — |
| | $ | 0.2 |
| | $ | — |
|
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair valueValue of long-term commodity derivatives,Long-Term Commodity Derivatives,” respectively.
(10) Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.
The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 20172018 and the six months ended June 30, 20182019 (in thousands):
| | Asset Retirement Obligations as of December 31, 2016 | $ | 32,256 |
| |
Asset Retirement Obligations as of December 31, 2017 | | $ | 10,787 |
|
Accretion expense | 2,322 |
| 419 |
|
Liabilities incurred for new wells and facilities construction | 253 |
| 93 |
|
Reductions due to sold wells and facilities | (21,466 | ) | (6,298 | ) |
Reductions due to plugged wells and facilities | (2,366 | ) | (180 | ) |
Revisions in estimates | (212 | ) | (562 | ) |
Asset Retirement Obligations as of December 31, 2017 (1) | $ | 10,787 |
| |
Asset Retirement Obligations as of December 31, 2018 | | $ | 4,259 |
|
Accretion expense | 243 |
| 168 |
|
Liabilities incurred for new wells and facilities construction | 26 |
| 102 |
|
Reductions due to sold wells and facilities | (6,265 | ) | — |
|
Reductions due to plugged wells and facilities | (145 | ) | (47 | ) |
Revisions in estimates | (85 | ) | 7 |
|
Asset Retirement Obligations as of June 30, 2018 (2) | $ | 4,561 |
| |
Asset Retirement Obligations as of June 30, 2019 | | $ | 4,489 |
|
(1) Includes
At both June 30, 2019 and December 31, 2018, approximately $2.1$0.3 million of currentour asset retirement obligations includedwere classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.
(2) Includes approximately $0.3 million The 2018 reductions due to sold wells and facilities are primarily attributable to the disposition of current asset retirement obligations included in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.our assets from our AWP Olmos field.
(11) Commitments and Contingencies
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. During the second quarter of 2019, the Company entered into new leases for compressors and operating equipment. Payment obligations under these leases are $3.0 million for the remainder of 2019, $6.1 million for 2020 and $1.8 million for 2021. There have been no other material changes to the Company's contractual obligations described in our December 31, 2018 Form 10-K.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 2018 are as follows (in thousands):
|
| | | |
| December 31, 2018 |
2019 | $ | 4,470 |
|
2020 | 838 |
|
2021 | 332 |
|
Thereafter | — |
|
Total undiscounted lease payments | $ | 5,640 |
|
The table above was prepared under the guidance of FASB Topic 840. As discussed in Note 3 above and in “Critical Accounting Policies and New Accounting Pronouncements,” the Company adopted the guidance of Topic 842, effective January 1, 2019.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with ourthe Company's financial information and ourits consolidated financial statements and accompanying notes included in this report and our annual reportits Annual Report on Form 10-K for the year ended December 31, 2017.2018. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 37 of this report.
Company Overview
SilverBow Resources is a growth orientedgrowth-oriented independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where we havethe Company has assembled approximatelyover 100,000 net acres across fivefour operating areas. OurThe Company's acreage positionsposition in each of ourits operating areas areis highly contiguous and designed for optimal and efficient horizontal well development. We haveThe Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. We leverageThe Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing ourits operations to maximize returns on capital invested.
We have transformed the Company from a conventional, Louisiana shallow water producer to a focused Eagle Ford player. Over the last few years we have successfully renegotiated midstream contracts, moved our headquarters to west Houston, and reduced headcount over 50%. We expect to continue our efforts to improve our G&A metrics as we execute on our strategic growth program. We continue to refine our portfolio, including the sale of certain AWP Olmos wells on March 1, 2018. This strategic divestiture allows us to better leverage existing personnel while lowering field-level costs on a per unit basis as it removes operational complexity from our portfolio. We believe there are other opportunities to continue streamlining our business to extract value for our shareholders.
Operational Results
Total production for the six months ended June 30, 20182019 increased 14%40% from the six months ended June 30, 20172018 to 160 Mmcfe/225 MMcfe/d primarily due to increased production from new wells in the Eagle Ford Shale, partially offset by the AWP Olmos divestiture and normal production declines. NaturalOil and natural gas liquids production for the six months ended June 30, 20182019 was 135 Mmcf/7,760 Boe/d, an increase of 15%81% from the six months ended June 30, 2017,2018, primarily driven by increased activity levelsdrilling in the Company’s FaskenLa Salle Condensate area combined with new activity in the Company’s Southern Eagle Ford gas window in Oro Grande, Uno Mas, and AWP. McMullen Oil area.
During the second quarter, of 2018, the Company spud sevendrilled six gross (seven(six net) wells while completing 12 gross (12 net) wells and bringing 16 gross (15 net) wells online. Activity primarily focused on the La Salle Condensate area where seven gross (six net) wells. The Companynet wells were completed two well pads in its Oro Grande and AWP areas and completed three wells of a six well pad in Fasken during the quarter. This Fasken sixThe Company remains focused on capital efficiencies while optimizing well pad included three Upper Eagle Ford wellsdesigns. For the second quarter, the Company realized a 28% improvement in drilling times over the full-year 2018 average, resulting in an average cost per lateral foot of $267, a 27% decrease over the same time frame. On the completions side, the Company averaged eight stages per day, an 80% increase over the full-year 2018 average, and three Lower Eagle Ford wells.
lowered completion costs per well by 43% over the same time frame.
The Company planscontinues to see strong results in its McMullen Oil and La Salle Condensate assets. The Hayes two-well pad in the McMullen Oil area was brought online early in the second quarter, and produced a 30-day per well average of 1,280 Boe/d (85% liquids). Both Hayes wells exceeded 11,000 feet in lateral length, while utilizing 2,400 pounds of proppant and 50 barrels of fluid per lateral foot. To date, both wells are performing in-line with the McMullen Oil area type curve on operating two rigs for the remainder of the year. The Company’s high specification rig, which was added in early March, will continue to focus on the western areas of the portfolio in Webb and Southwest LaSalle counties while the other rig focuses on our Southern Eagle Ford gas assets in LaSalle, McMullen and Live Oak Counties.a per lateral foot basis. The Company maintains considerable flexibilityplans to modify the drilling program based on well results, commodity prices and other strategic opportunities. For the full year, the Company remains on track to drill 31-33 and complete 25-27 netthree additional McMullen Oil wells with the majority of the activity occurring in the second half of the year. In the La Salle Condensate area, the Company completed its Briggs three-well pad, which was brought online in late May and produced a 30-day per well average of 977 Boe/d (75% liquids). The Company plans on drillingcompleted the three wells in all areasan average of nine days, with costs coming in 10% below expectations.
Through the first half of 2019, the Company successfully added to its portfolio during 2018, with a continued focus on demonstratingacreage position through an organic leasing campaign. This includes approximately 1,000 net acres directly offsetting the commercial viability ofCompany's prolific Fasken property, which provides for 12 high-return, long-lateral locations. In addition, the Company’s extensive drilling inventory.Company is well-positioned to further its operational and technical efficiencies.
2019 cost reduction initiatives:The Company continues to evaluate completion designs across its asset base assessing stage lengths, clusters per stage, fluid volumes, and proppant types/concentrations. The Company is integrating new concepts to improve asset performance, increase capital efficiency, and reduce operating costs. The Company completed two wells in its Oro Grande acreage during the second quarter. These wells were completed with an average of 3,700 pounds of proppant per foot of lateral, the Company’s highest intensity fracture stimulations to date.
In the second quarter, the Company also completed two wells in southern AWP, including the Bracken EF 26H which was the Company's second longest lateral at 9,220 feet. Both wells were completed using an average of 2,600 pounds of proppant per foot of lateral, with stage spacing of 170 feet. In addition, the Company finished operations on its first two 100% slickwater
fracs, completing one Upper and one Lower Eagle Ford Fasken well in early July. These wells were stimulated with 2,500 pounds of proppant per foot of lateral. The Company has turned all four of these wells to production as of July of 2018.
In the month of July, the Company brought eight new wells to sales compared to two net wells in the second quarter.
2018 cost reduction initiatives: We continue to focus on cost efficient operations and took additional actionsreduction measures. Initiatives include the use of regional sand in the first six months of 2018 to reduce operating and overhead costs. These initiatives included field staff reductions, disposition of uneconomic and higher cost properties, fullcompletions, improved utilization of existing facilities, elimination of redundant equipment, and replacement of rental equipment with company-owned equipment. We have also improved our processesAs previously mentioned, the Company continues to improve its process for drilling and completing wells. OurThe Company's procurement team takes a diligent and systematicprocess-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most detailed level. Services are commonly sourced directly from the suppliers, which has led to a significant reduction in ourthe Company's overall lease operating expenses at the field level. For example, our South Texasthe Company's lease operating expenses were $0.30/$0.25/Mcfe for the first six months of 2018 which2019, as compared to $0.41/$0.30/Mcfe for the same period a year ago. For the third quarter, we are guiding for lease operating expenses of $0.25 to $0.27, and we expect our metrics to improve throughout the year as production increases.in 2018.
Additionally, our significant operational control and manageable leasehold obligations provide us the flexibility to control our costs as we transition to a development mode across our portfolio. At the corporate level, we have also undergone additional staff reductions, reduced the square footage of leased office space and are taking additional steps to further reduce overhead costs. These actions have led toThe Company's cash general and administrative costs were $9.6 million (a non-GAAP financial measure calculated as $12.9 million in net general and administrative costs less $3.3 million of share based compensation) for the first six months of 2019, or $0.23 per Mcfe, compared to $8.7 million (a non-GAAP financial measure calculated as $11.4 million in net general and administrative costs less $2.7 million of share based compensation) for the first six months of 2018 or $0.30 per Mcfe, compared to $13.5 million (a non-GAAP financial measure calculated as $16.6 million in net general and administrative costs less $3.1 million of share based compensation), or $0.53 per $0.30/Mcfe, for the six months ended June 30, 2017.
Strategic dispositions: On March 1, 2018, the Company divested certain wells in its AWP Olmos field for $27.0 million in cash plus the assumption by the buyer of $6.3 million of asset retirement obligations. This transaction had an effective date of January 1, 2018. These assets are located in McMullen County, Texas and include approximately 491 wells with total proved reserves of 28 Bcfe (100% proved developed) as of December 31, 2017. Full year 2017 production from these properties was approximately 9.5 Mmcfe/d (57% natural gas). Cash proceeds from the sale were used to repay outstanding borrowings under the Company’s Credit Facility.
Liquidity and Capital Resources
OurThe Company's primary use of cash flow has been to fund capital expenditures to develop ourits oil and gas properties. We expect to make capital expenditures of $245 million to $265 million during 2018. We made $84 million of capital expenditures during the six months ended June 30, 2018, and capital expenditures are expected to increase in the third quarter of 2018 as a result of having two rigs running during the entire quarter. As of June 30, 2018,2019, the Company’s liquidity consisted of approximately $6.6$3.3 million of cash-on-hand and $248.0$137.0 million in available borrowings on our $330the Credit Facility, which has a $410.0 million borrowing base under our Credit Facility.base. Management believes the Company has sufficient liquidity to meet its obligations duringand fund our planned capital expenditures for at least the next 12 months and execute its long-term development plans. See Note 6 to ourthe Company's condensed consolidated financial statements for more information on ourits Credit Facility and Second Lien.Facility.
Contractual Commitments and Obligations
During the firstsecond quarter of 2018, we incurred commitments of approximately $9.02019, the Company entered into new leases for compressors and operating equipment. Payment obligations under these leases are $3.0 million for drilling services to be provided over the next year. We hadremainder of 2019, $6.1 million for 2020 and $1.8 million for 2021.
There were no other material changes in ourthe Company's contractual commitments during the six months ended June 30, 20182019 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2017.2018.
Off-Balance Sheet Arrangements
As of June 30, 2018,2019, we had no off-balance sheet arrangements requiring disclosure pursuant to articleItem 303(a) of Regulation S-K.
Summary of First Half 2018First-Half 2019 Financial Results
Revenues and net income (loss): The Company's oil and gas revenues were $146.8 million for the six months ended June 30, 2019, compared to $104.1 million for the six months ended June 30, 2018, compared to $88.2 million for the six months ended June 30, 2017.2018. Revenues were higher primarily due to overall increased production, as well as higher oil and NGL pricing, partially offset by lower natural gascommodity pricing. The Company's net income was $80.8 million for the six months ended June 30, 2019, compared to $10.8 million for the six months ended June 30, 2018, compared to $34.0 million for the six months ended June 30, 2017.2018. The decreaseincrease was primarily due lossesto overall increased production during the current period compared to the prior period and gains on commodity derivatives.derivatives and a benefit recorded for income tax expense for reversal of a valuation allowance for the company's deferred tax assets.
Capital expenditures: The Company's capital expenditures on a cashan accrual basis were $84.1$158 million for the six months ended June 30, 20182019 compared to $85.7$117.1 million for the six months ended June 30, 2017.2018. The expenditures for the six months ended June 30, 2019 and 2018 were primarily driven by continued legacy developmentattributable to drilling and Southern Eagle Ford gas window delineation, while expenditures for the six months ended June 30, 2017, were primarily driven by development activity at our Fasken and AWP fields in the Eagle Ford play.completion activity.
Working capital: The Company had a working capital deficit of $68.9$20.5 million at June 30, 20182019 and a deficit of $32.9$39.7 million at December 31, 2017.2018. The working capital computation does not include available liquidity through our Credit Facility.
Cash Flows: For the six months ended June 30, 2019, the Company generated cash from operating activities of $100.3 million, of which $6.3 million was attributable to changes in working capital. Cash used for property additions was $174.1 million. This included $16.5 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $2.8 million was paid during the six months ended June 30, 2019, for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowings on the revolving Credit Facility were $78.0 million during the six months ended June 30, 2019.
For the six months ended June 30, 2018, the Company generated cash from operating activities of $53.0 million, of which $5.6 million was attributable to changes in working capital. Cash used for property additions was $84.1 million. This excluded $35.3 million attributable to a net increase of capital relatedcapital-related payables and accrued costs. Additionally, $6.0 million was paid during the six months ended June 30, 2018 for property sale obligations related to the sale of our former Bay De Chene field. The Company’s net borrowingspayments on the revolving Credit Facility were $9.0 million, duringwhich includes the six months ended June 30, 2018.
For the six months ended June 30, 2017, the Company generated cash from operating activities of $44.0 million, of which $2.9 million was attributable to changes in working capital. Cash used for property additions was $85.7 million; however, this does not include $5.4 million attributable to a net increase of capital related payables and accrued costs. The Company’s net borrowingspay-down on the revolving Credit Facility were $13.0 million for this period. Additionally, for the six months ended June 30, 2017 the Company received $39.2 millionborrowings with proceeds from financing activities in connection with its share purchase agreement for the Company's common stock.our AWP Olmos field sale.
Results of Operations
Revenues — Three Months Ended June 30, 20182019 and Three Months Ended June 30, 20172018
Natural gas production was 77% and 86% and 83% of ourthe Company's production volumes for the three months ended June 30, 20182019 and 2017,2018, respectively. Natural gas sales were 71%58% and 77%71% of oil and gas sales for the three months ended June 30, 20182019 and 2017,2018, respectively.
Crude oil production was 11% and 6% of ourthe Company's production volumes for each of the three months ended June 30, 2019 and 2018, and 2017.respectively. Crude oil sales were 19%33% and 14%19% of oil and gas sales for the three months ended June 30, 20182019 and 2017,2018, respectively.
NGL production was 12% and 8% and 11% of ourthe Company's production volumes for the three months ended June 30, 20182019 and 2017,2018, respectively. NGL sales were 10%8% and 9%10% of oil and gas sales for the three months ended June 30, 20182019 and 2017,2018, respectively.
The following tables providetable provides additional information regarding ourthe Company's oil and gas sales, by area, excluding any effects of ourthe Company's hedging activities, for the three months ended June 30, 20182019 and 2017:2018:
| | Fields | | Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2017 | | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 |
| | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) |
Artesia Wells | | $ | 11.6 |
| 2,290 |
| | $ | 3.7 |
| 946 |
| | $ | 19.9 |
| 4,829 |
| | $ | 11.6 |
| 2,290 |
|
AWP | | 8.8 |
| 1,665 |
| | 14.2 |
| 3,491 |
| | 21.4 |
| 4,107 |
| | 8.8 |
| 1,665 |
|
Fasken | | 25.3 |
| 8,644 |
| | 27.5 |
| 8,717 |
| | 21.5 |
| 7,984 |
| | 25.3 |
| 8,644 |
|
Other (1) | | 5.6 |
| 1,941 |
| | 0.4 |
| 128 |
| | 11.9 |
| 4,465 |
| | 5.6 |
| 1,941 |
|
Total | | $ | 51.3 |
| 14,540 |
| | $ | 45.8 |
| 13,282 |
| | $ | 74.7 |
| 21,385 |
| | $ | 51.3 |
| 14,540 |
|
(1) Primarily composed of ourthe Company's Oro Grande and Uno Mas fields.
The sales volumes increase from 20172018 to 20182019 was primarily due to increased natural gas production andas a result of increased drilling and completion activity.
In the second quarter of 2018,2019, our $5.6$23.3 million, or 12%45% increase, in oil, NGL and natural gas sales from the prior year period resulted from:
Price variances that had an approximate $1.5approximately $11.8 million unfavorable impact on sales due to overall lower commodity pricing; and
Volume variances that had an approximately $35.2 million favorable impact on sales due to the higher oil and NGL pricing, partially offset by lower natural gas pricing; and
Volume variances that had an $4.0 million favorable impact on sales due to oil and natural gas production, partially offset by lower NGLoverall increased commodity production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended June 30, 20182019 and 20172018 (in thousands, except per-dollar amounts):
| |
| | Three Months Ended June 30, 2018 | Three Months Ended June 30, 2017 | | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 |
Production volumes: | |
| |
|
Oil (MBbl) (1) | | 141 |
| 139 |
| | 405 |
| 141 |
|
Natural gas (MMcf) | | 12,433 |
| 11,078 |
| | 16,409 |
| 12,433 |
|
Natural gas liquids (MBbl) (1) | | 211 |
| 228 |
| | 424 |
| 211 |
|
Total (MMcfe) | | 14,540 |
| 13,282 |
| | 21,385 |
| 14,540 |
|
| | | | |
Oil, Natural gas and Natural gas liquids sales: | |
| |
Oil, natural gas and natural gas liquids sales: | | |
|
Oil | | $ | 9,638 |
| $ | 6,527 |
| | $ | 24,940 |
| $ | 9,638 |
|
Natural gas | | 36,369 |
| 35,043 |
| | 43,597 |
| 36,369 |
|
Natural gas liquids | | 5,339 |
| 4,215 |
| | 6,166 |
| 5,339 |
|
Total | | $ | 51,347 |
| $ | 45,785 |
| | $ | 74,703 |
| $ | 51,347 |
|
| | | | |
Average realized price: | |
| |
|
Oil (per Bbl) | | $ | 68.53 |
| $ | 46.82 |
| | $ | 61.60 |
| $ | 68.53 |
|
Natural gas (per Mcf) | | 2.93 |
| 3.16 |
| | 2.66 |
| 2.93 |
|
Natural gas liquids (per Bbl) | | 25.36 |
| 18.49 |
| | 14.53 |
| 25.36 |
|
Average per Mcfe | | $ | 3.53 |
| $ | 3.45 |
| | $ | 3.49 |
| $ | 3.53 |
|
| | | | |
Price impact of cash-settled derivatives: | |
| |
|
Oil (per Bbl) | | $ | (14.76 | ) | $ | (0.11 | ) | | $ | (0.01 | ) | $ | (14.76 | ) |
Natural gas (per Mcf) | | (0.06 | ) | (0.14 | ) | | 0.17 |
| (0.06 | ) |
Natural gas liquids (per Bbl) | | (2.11 | ) | — |
| | 3.78 |
| (2.11 | ) |
Average per Mcfe | | $ | (0.22 | ) | $ | (0.12 | ) | | $ | 0.20 |
| $ | (0.22 | ) |
| | | | |
Average realized price including cash settled derivatives: | |
| |
Average realized price including impact of cash-settled derivatives: | | |
|
Oil (per Bbl) | | $ | 53.76 |
| $ | 46.71 |
| | $ | 61.59 |
| $ | 53.76 |
|
Natural gas (per Mcf) | | 2.87 |
| 3.02 |
| | 2.82 |
| 2.87 |
|
Natural gas liquids (per Bbl) | | 23.25 |
| 18.49 |
| | 18.31 |
| 23.25 |
|
Average per Mcfe | | $ | 3.31 |
| $ | 3.33 |
| | $ | 3.69 |
| $ | 3.31 |
|
| | | | |
|
(1) Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six McfeMcfe.
For the three months ended June 30, 20182019 and 2017,2018, the Company recorded net gains of $25.0 million and net losses of $10.8 million and net gains of $5.1 million from our derivativederivatives activities, respectively. Hedging activity is recorded in “Net gain“Gain (loss) on commodity derivatives”derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Three Months Ended June 30, 20182019 and Three Months Ended June 30, 20172018
The following table provides additional information regarding our expenses for the three months ended June 30, 20182019 and 2017:2018:
| | Costs and Expenses | Three Months Ended June 30, 2018 | Three Months Ended June 30, 2017 | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 |
General and administrative, net | $ | 5,794 |
| $ | 6,811 |
| $ | 6,624 |
| $ | 5,794 |
|
Depreciation, depletion, and amortization | 13,096 |
| 10,828 |
| 24,029 |
| 13,096 |
|
Accretion of asset retirement obligation | 84 |
| 576 |
| |
Accretion of asset retirement obligations | | 86 |
| 84 |
|
Lease operating cost | 3,760 |
| 4,776 |
| 5,035 |
| 3,760 |
|
Workovers | | (127 | ) | — |
|
Transportation and gas processing | 5,421 |
| 4,761 |
| 6,728 |
| 5,421 |
|
Severance and other taxes | 2,662 |
| 2,280 |
| 3,950 |
| 2,662 |
|
Interest expense, net | 6,585 |
| 4,642 |
| 9,306 |
| 6,585 |
|
Total Costs and Expenses | $ | 37,402 |
| $ | 34,674 |
| |
General and Administrative Expenses, Net. These expenses on a per Mcfeper-Mcfe basis were $0.40$0.31 and $0.51$0.40 for the three months ended June 30, 20182019 and 2017,2018, respectively. The decrease per Mcfe was due to higher production while the increase in costs was primarily due to lowerhigher temporary labor, higher salaries and burdens and decreases in other expenses as a result of our cost reduction initiatives.higher computer operation expenses. Included in general and administrative expenses is $1.3$1.6 million and $1.6$1.3 million in share based compensation for the three months ended June 30, 20182019 and 2017,2018, respectively.
Depreciation, Depletion and Amortization (“DD&A”).Amortization. These expenses on a per Mcfeper-Mcfe basis were $0.90$1.12 and $0.82$0.90 for the three months ended June 30, 20182019 and 2017,2018, respectively. The increase in the rate per unit is primarily due to a higher depletable base relative to reserves. The higher depletion expense is due to a higher production and a higher per unit rate.
Lease operating costOperating Cost. These expenses on a per Mcfeper-Mcfe basis were $0.26$0.23 and $0.36$0.26 for the three months ended June 30, 20182019 and 2017,2018, respectively. The decrease per Mcfe was primarily due to divestitures of assets and a concentrated effort by the Company to reduce overall operating costs.costs, along with higher production.
Transportation and gas processing.Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.37$0.31 and $0.36$0.37 for the three months ended June 30, 20182019 and 2017,2018, respectively.
Severance and Other Taxes. These expenses on a per Mcfeper-Mcfe basis were $0.18 and $0.17 for each of the three months ended June 30, 20182019 and 2017, respectively.2018. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.2%5.3% and 5.0%5.2% for the three months ended June 30, 2019 and 2018, and 2017.respectively.
Interest. Our gross interest cost was $6.8$9.4 million and $4.8$6.8 million for the three months ended June 30, 20182019 and 2017,2018, respectively. The increase in gross interest cost is primarily due to the interest on our Second Lien, partially offset by lower interest on ourincreased Credit Facility due to decreased borrowings. Interest cost of $0.3$0.1 million and $0.2$0.3 million was capitalized infor the second quarters of 2018three months ended June 30, 2019 and 2017, respectively.2018.
Income Taxes. There was no expense for Federalfederal income taxes in each of the three months ended June 30, 2018 and 2017 as the Company had significant deferred tax assets in excess of deferred tax liabilities. Because of uncertainty about the realization of any future tax benefits,In prior periods, management had determined that it was not more likely than not that the Company has carriedwould realize future cash benefits from its remaining federal carryover items and, accordingly, had taken a full valuation allowance againstto offset its Federaltax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in a net deferred tax asset balance. Federal tax expense for income related to these periods was offset by reductions in our valuation allowance. We recognized $0.3benefit of $20.7 million for deferred state income tax expense during the three months ended June 30, 2018. There was no state income tax expense recorded for the three months ended June 30, 2017.2019. State income tax expense of $0.3 million was recognized for the three months ended June 30, 2018.
Results of Operations
Revenues — Six Months Ended June 30, 20182019 and Six Months Ended June 30, 20172018
Natural gas production was 79% and 84% and 83% of ourthe Company's production volumes for the six months ended June 30, 20182019 and 2017,2018, respectively. Natural gas sales were 69%65% and 75%69% of oil and gas sales for the six months ended June 30, 20182019 and 2017,2018, respectively.
Crude oil production was 10% and 7% of ourthe Company's production volumes for each of the six months ended June 30, 2019 and 2018, and 2017.respectively. Crude oil sales were 20%27% and 16%20% of oil and gas sales for the six months ended June 30, 20182019 and 2017,2018, respectively.
NGL production was 11% and 9% and 10% of ourthe Company's production volumes for the six months ended June 30, 20182019 and 2017,2018, respectively. NGL sales were 11%8% and 9%11% of oil and gas sales for the six months ended June 30, 20182019 and 2017,2018, respectively.
The following tables providetable provides additional information regarding ourthe Company's oil and gas sales, by area, excluding any effects of ourthe Company's hedging activities, for the six months ended June 30, 20182019 and 2017:2018:
| | Fields | | Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2017 | | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
| | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) |
Artesia Wells | | $ | 23.9 |
| 4,814 |
| | $ | 7.9 |
| 1,962 |
| | $ | 33.0 |
| 7,884 |
| | $ | 23.9 |
| 4,814 |
|
AWP | | 20.9 |
| 4,117 |
| | 27.8 |
| 6,637 |
| | 37.5 |
| 7,127 |
| | 20.9 |
| 4,117 |
|
Fasken | | 49.0 |
| 16,632 |
| | 52.0 |
| 16,729 |
| | 46.9 |
| 15,817 |
| | 49.0 |
| 16,632 |
|
Other (1) | | 10.3 |
| 3,446 |
| | 0.5 |
| 160 |
| | 29.4 |
| 9,916 |
| | 10.3 |
| 3,446 |
|
Total | | $ | 104.1 |
| 29,009 |
| | $ | 88.2 |
| 25,488 |
| | $ | 146.8 |
| 40,744 |
| | $ | 104.1 |
| 29,009 |
|
(1) Primarily composed of ourthe Company's Oro Grande and Uno Mas fields.
The sales volumes increase from 20172018 to 20182019 was primarily due to increased natural gas production andas a result of increased drilling and completion activity.
In the first six months of 2018,2019, our $15.9$42.6 million, or 18%41% increase, in oil, NGL and natural gas sales from the prior year period resulted from:
Price variances that had an approximate $4.0approximately $10.5 million favorableunfavorable impact on sales due to the higher oil and NGL pricing, partially offset byoverall lower natural gascommodity pricing; and
Volume variances that had an $11.9approximately $53.2 million favorable impact on sales due to overall higher volumeincreased commodity production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the six months ended June 30, 20182019 and 20172018 (in thousands, except per-dollar amounts):
| |
| | Six Months Ended June 30, 2018 | Six Months Ended June 30, 2017 | | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
Production volumes: | | | | |
Oil (MBbl) (1) | | 318 |
| 286 |
| | 661 |
| 318 |
|
Natural gas (MMcf) | | 24,349 |
| 21,182 |
| | 32,316 |
| 24,349 |
|
Natural gas liquids (MBbl) (1) | | 459 |
| 432 |
| | 743 |
| 459 |
|
Total (MMcfe) | | 29,009 |
| 25,488 |
| | 40,744 |
| 29,009 |
|
| | | | |
Oil, Natural gas and Natural gas liquids sales: | | | |
Oil, natural gas and natural gas liquids sales: | | | |
Oil | | $ | 21,078 |
| $ | 13,728 |
| | $ | 39,547 |
| $ | 21,078 |
|
Natural gas | | 72,136 |
| 66,106 |
| | 94,902 |
| 72,122 |
|
Natural gas liquids | | 10,900 |
| 8,363 |
| | 12,319 |
| 10,900 |
|
Total | | $ | 104,113 |
| $ | 88,197 |
| | $ | 146,768 |
| $ | 104,099 |
|
| | | | |
Average realized price: | | | | |
Oil (per Bbl) | | $ | 66.33 |
| $ | 48.07 |
| | $ | 59.79 |
| $ | 66.33 |
|
Natural gas (per Mcf) | | 2.96 |
| 3.12 |
| | 2.94 |
| 2.96 |
|
Natural gas liquids (per Bbl) | | 23.75 |
| 19.36 |
| | 16.58 |
| 23.75 |
|
Average per Mcfe | | $ | 3.59 |
| $ | 3.46 |
| | $ | 3.60 |
| $ | 3.59 |
|
| | | | |
Price impact of cash-settled derivatives: | | | | |
Oil (per Bbl) | | $ | (11.20 | ) | $ | (1.50 | ) | | $ | (0.19 | ) | $ | (11.20 | ) |
Natural gas (per Mcf) | | 0.07 |
| (0.09 | ) | | 0.09 |
| 0.07 |
|
Natural gas liquids (per Bbl) | | (1.38 | ) | — |
| | 3.33 |
| (1.38 | ) |
Average per Mcfe | | $ | (0.09 | ) | $ | (0.09 | ) | | $ | 0.13 |
| $ | (0.09 | ) |
| | | | |
Average realized price including cash settled derivatives: | | | |
Average realized price including impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | 55.13 |
| $ | 46.57 |
| | $ | 59.60 |
| $ | 55.13 |
|
Natural gas (per Mcf) | | 3.03 |
| 3.03 |
| | 3.03 |
| 3.03 |
|
Natural gas liquids (per Bbl) | | 22.38 |
| 19.36 |
| | 19.91 |
| 22.38 |
|
Average per Mcfe | | $ | 3.50 |
| $ | 3.37 |
| | $ | 3.73 |
| $ | 3.50 |
|
| | | | |
|
(1) Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six McfeMcfe.
For the six months ended June 30, 20182019 and 2017,2018, the Company recorded net lossesgains of $17.1$20.9 million and net gainslosses of $16.1$17.1 million from our derivative activities, respectively. Hedging activity is recorded in “Net gain“Gain (loss) on commodity derivatives”derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Six Months Ended June 30, 20182019 and Six Months Ended June 30, 20172018
The following table provides additional information regarding our expenses for the six months ended June 30, 20182019 and 2017:2018:
| | Costs and Expenses | Six Months Ended June 30, 2018 | Six Months Ended June 30, 2017 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
General and administrative, net | $ | 11,370 |
| $ | 16,645 |
| $ | 12,900 |
| $ | 11,370 |
|
Depreciation, depletion, and amortization | 26,228 |
| 20,543 |
| 45,834 |
| 26,228 |
|
Accretion of asset retirement obligation | 243 |
| 1,140 |
| |
Accretion of asset retirement obligations | | 168 |
| 243 |
|
Lease operating cost | 8,721 |
| 10,549 |
| 9,567 |
| 8,721 |
|
Workovers | | 519 |
| — |
|
Transportation and gas processing | 10,446 |
| 9,146 |
| 13,135 |
| 10,446 |
|
Severance and other taxes | 5,692 |
| 3,898 |
| 7,266 |
| 5,692 |
|
Interest expense, net | 12,474 |
| 8,249 |
| 18,065 |
| 12,474 |
|
Total Costs and Expenses | $ | 75,174 |
| $ | 70,170 |
| |
General and Administrative Expenses, Net. These expenses on a per Mcfeper-Mcfe basis were $0.39$0.32 and $0.65$0.39 for the six months ended June 30, 20182019 and 2017,2018, respectively. The decrease per Mcfe was due to higher production while the increase in costs was primarily due to lowerhigher temporary labor, higher salaries and burdens and decreases in other expenses as a result of our cost reduction initiatives.higher computer operation expenses. Included in general and administrative expenses is $2.7$3.3 million and $3.1$2.7 million in share based compensation for the six months ended June 30, 20182019 and 2017,2018, respectively.
Depreciation, Depletion and Amortization (“DD&A”).Amortization. These expenses on a per Mcfeper-Mcfe basis were $0.90$1.12 and $0.81$0.90 for the six months ended June 30, 20182019 and 2017,2018, respectively. The increase in the rate per unit is primarily due to a higher depletable base relative to reserves. The higher depletion expense is due to a higher production and a higher per unit rate.
Lease operating costOperating Cost. These expenses on a per Mcfeper-Mcfe basis were $0.30$0.25 and $0.41$0.30 for the six months ended June 30, 20182019 and 2017,2018, respectively. The decrease per Mcfe was primarily due to divestitures of assets and a concentrated effort by the Company to reduce overall operating costs.costs, along with higher production.
Transportation and gas processing.Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per Mcfe basis were $0.32 and $0.36 for each of the six months ended June 30, 2019 and 2018, and 2017.respectively.
Severance and Other Taxes. These expenses on a per Mcfe basis were $0.20$0.18 and $0.15$0.20 for the six months ended June 30, 20182019 and 2017,2018, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.5%5.0% and 4.4%5.5% for the six months ended June 30, 2019 and 2018, and 2017. This increase is primarily due to an estimated increase in the taxable base for ad valorem tax and higher severance tax rates on new wells which realized a lower rate benefit under the Texas high cost well incentive program.respectively.
Interest. Our gross interest cost was $13.1$18.3 million and $8.6$13.1 million for the six months ended June 30, 20182019 and 2017,2018, respectively. The increase in gross interest cost is primarily due to the interest on our Second Lien, partially offset by lower interest on ourincreased Credit Facility due to decreased borrowings. Interest cost of $0.7$0.2 million and $0.4$0.7 million was capitalized infor the second quarters of 2018six months ended June 30, 2019 and 2017, respectively.2018.
Income Taxes. There was no expense for Federalfederal income taxes in each of the six months ended June 30, 2018 and 2017 as the Company had significant deferred tax assets in excess of deferred tax liabilities. Because of uncertainty about the realization of any future tax benefits,In prior periods, management had determined that it was not more likely than not that the Company has carriedwould realize future cash benefits from its remaining federal carryover items and, accordingly, had taken a full valuation allowance againstto offset its Federaltax assets. During the second quarter of 2019, the Company was able to complete several operational initiatives that resulted in increased production, lower development costs and expanded inventory of development prospects. The results of these initiatives led management to determine, after weighing both positive and negative evidence, that the Company will more likely than not be able to realize the benefits of its deferred tax assets. Accordingly, the Company released the valuation allowance, resulting in a net deferred tax asset balance. Federal tax expense for income related to these periods was offset by reductions in our valuation allowance. We recognized $0.3benefit of $20.5 million for deferred state income tax expense during the six months ended June 30, 2018. There was no state income tax expense recorded for the six months ended June 30, 2017.2019. State income tax of $0.3 million was recognized for the six months ended June 30, 2018.
Non-GAAP Financial Measures
Adjusted EBITDA
We present adjusted EBITDA attributable to common stockholders (“Adjusted EBITDA”) in addition to our reported net income (loss) in accordance with U.S. GAAP. Adjusted EBITDA is a non-GAAP financial measure that is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costscost basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. We define Adjusted EBITDA as net income (loss):
Plus/(Less):
Depreciation, depletion and amortization;
Accretion of asset retirement obligations;
Interest expense;
Impairment of oil and natural gas properties;
Net losses (gains) on commodity derivative contracts;
Amounts collected (paid) for commodity derivative contracts held to settlement;
Income tax expense (benefit); and
Share-based compensation expense.
Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
The following tables present reconciliations of our net income (loss) to Adjusted EBITDA for the periods indicated (in thousands):
| |
| Three Months Ended June 30, 2018 | Three Months Ended June 30, 2017 | Three Months Ended June 30, 2019 | Three Months Ended June 30, 2018 |
Net Income (Loss) | $ | 2,319 |
| $ | 16,241 |
| $ | 64,704 |
| $ | 2,319 |
|
Plus: |
|
|
Depreciation, depletion and amortization | 13,096 |
| 10,828 |
| 24,029 |
| 13,096 |
|
Accretion of asset retirement obligations | 84 |
| 576 |
| 86 |
| 84 |
|
Interest expense | 6,585 |
| 4,642 |
| 9,306 |
| 6,585 |
|
Derivative (gain)/loss | 10,752 |
| (5,132 | ) | (24,925 | ) | 10,752 |
|
Derivative cash settlements collected/(paid) (1) | (3,212 | ) | (1,621 | ) | 4,319 |
| (3,212 | ) |
Income tax expense/(benefit) | 328 |
| — |
| (20,735 | ) | 328 |
|
Share-based compensation expense | 1,316 |
| 1,632 |
| 1,648 |
| 1,316 |
|
Adjusted EBITDA | $ | 31,268 |
| $ | 27,166 |
| $ | 58,432 |
| $ | 31,268 |
|
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period. |
| |
| Six Months Ended June 30, 2018 | Six Months Ended June 30, 2017 | Six Months Ended June 30, 2019 | Six Months Ended June 30, 2018 |
Net Income (Loss) | $ | 10,787 |
| $ | 33,951 |
| $ | 80,757 |
| $ | 10,787 |
|
Plus: |
| |
Depreciation, depletion and amortization | 26,228 |
| 20,543 |
| 45,834 |
| 26,228 |
|
Accretion of asset retirement obligations | 243 |
| 1,140 |
| 168 |
| 243 |
|
Interest expense | 12,474 |
| 8,249 |
| 18,065 |
| 12,474 |
|
Derivative (gain)/loss | 17,107 |
| (16,068 | ) | (20,903 | ) | 17,107 |
|
Derivative cash settlements collected/(paid) (1) | (2,476 | ) | (2,289 | ) | 5,366 |
| (2,476 | ) |
Income tax expense/(benefit) | 328 |
| — |
| (20,503 | ) | 328 |
|
Share-based compensation expense | 2,675 |
| 3,136 |
| 3,339 |
| 2,675 |
|
Adjusted EBITDA | $ | 67,366 |
| $ | 48,662 |
| $ | 112,123 |
| $ | 67,366 |
|
(1) This includes accruals for settled contracts covering commodity deliveries during the period where the actual cash settlements occur outside of the period. |
Critical Accounting Policies and New Accounting Pronouncements
Revenue Recognition. Effective January 1, 2018, we adopted ASC 606 - Revenue from Contracts with Customers using the modified retrospective method of adoption. Adoption of this standard did not result in anyThere have been no changes to our reporting. See Note 3 to our condensed consolidated financial statements for more information.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method.
The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.
The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of the impairment of unproved properties. The estimation process for both reserves and the impairment of unproved properties is subjective, and results may change over time based on current information and industry conditions. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects ("Ceiling Test").
We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.
If future capital expenditures outpace future discounted net cash flowscritical accounting policies disclosed in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.2018 Annual Report on Form 10-K.
New Accounting Pronouncements. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to record mostcertain leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. At this time, we do not anticipateThe Company adopted the guidance to have a detrimentalon January 1, 2019, with no significant impact on the company's financial statements resulting from implementation. See Note 3 to our covenant compliance under our Credit Agreement. See Note 2 to our condensed consolidated financial statements for more information.
Forward-Looking Statements
This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
• volatility in natural gas, oil and NGL prices;
• future cash flows and their adequacy to maintain our ongoing operations;
• liquidity, including our ability to satisfy our short- or long-term liquidity needs;
• our borrowing capacity, future covenant compliance, cash flows and liquidity;
• operating results;
• asset disposition efforts or the timing or outcome thereof;
• ongoing and prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;
• the amount, nature and timing of capital expenditures, including future development costs;
• timing, cost and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability, cost and terms of capital;
• drilling of wells;
• availability and cost for transportation of oil and natural gas;
• costs of exploiting and developing our properties and conducting other operations;
• competition in the oil and natural gas industry;
• general economic conditions;
• opportunities to monetize assets;
• effectiveness of our risk management activities;
• environmental liabilities;
• counterparty credit risk;
• governmental regulation and taxation of the oil and natural gas industry;
• developments in world oil and gas markets and in oil and natural gas-producing countries;
• uncertainty regarding our future operating results; and
• other risks and uncertainties described in Item 1A. “Risk Factors” in this quarterly reportQuarterly Report on Form 10-Q and our annual reportAnnual Report on Form 10-K for the year ended December 31, 2017.2018.
All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our annual reportAnnual Report on Form 10-K for the year ended December 31, 2017.2018. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions
to any such
forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price swings in recent periods.
Our price-riskprice risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price-riskprice risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.
Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and, when considered necessary, we also obtain letters of credit from certain customers, parent company guarantees if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
Concentration of Sales Risk. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.
Interest Rate Risk. At June 30, 20182019, we had $82.0a combined $473.0 million drawn under our Credit Facility and our Second Lien, which has abear floating raterates of interest and therefore isare susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at June 30, 2019 would increase our annual interest expense by $4.7 million.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as
As of the end of the period covered by this quarterly report on Form 10-Q, the Company’s management carried out an evaluation, under the supervision and have determined that suchwith the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of result of the material weakness in our internal control over financial reporting more fully described below, our disclosure controls and procedures were not effective at a level that provides reasonable assurance as of the last day of the period covered by this report.
However, the Company concluded that the existence of this material weakness did not result in material misstatement of the Company’s financial statements included in this Quarterly Report or of those of any prior period.
Income Taxes
In connection with the preparation of our financial statements for the three months ended June 30, 2019, we identified a material weakness over certain aspects of accounting for income taxes. More specifically, we have determined that the design and operation of the controls over our income tax accounting process related to the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions were not effective. Due to the infrequency and nature of accounting for adjustments to deferred income tax expense, the Company does not have the expertise in-house and engaged a third-party accounting firm to assist. Following closing of the Company’s books and records for the three months ended June 30, 2019 but before this Quarterly Report was filed, the Company’s independent registered public accounting firm notified the Company of the improper accounting treatment of the deferred income tax adjustment. Until this material weakness is remediated, there is a reasonable possibility that a material misstatement of our interim financial statements will not be prevented or detected on a timely basis.
Remediation Measures
We are effective.committed to remediating the control deficiency that gave rise to the material weakness described above. Management is responsible for implementing changes and improvements to internal control over financial reporting and for remediating the control deficiency that gave rise to the material weakness.
With oversight from the Audit Committee, we intend to take the necessary steps to remediate the material weakness by enhancing our internal controls to ensure proper review by and communication between our external tax advisors and internal accounting personnel. Our efforts will consist primarily of strengthening our tax organization through continuing training and education and designing controls related to the components of our income tax process to enhance our management review controls over income taxes.
As part of the key remediation actions, we will:
Review our income tax processes and controls and enhance the overall design and procedures performed upon the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions;
Re-design our management review controls and enhance the precision of review around the key income tax areas relating to the allocation of intra-period adjustments to deferred income tax expense; and
Evaluate the sufficiency of our income tax resources and personnel to determine whether additional resources are needed.
The material weakness will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.
Changes in Internal Control Over Financial Reporting
ThereExcept as noted above, there was no change in our internal control over financial reporting during the three months ended June 30, 2018,2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings.
No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.
Item 1A. Risk Factors.
A description of our risk factors can be found in “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. There have beenwere no material changes to those risk factors during the six months ended June 30, 2019, except that the below risk factor is hereby added:
We have identified a material weakness in our risk factors disclosedinternal control over financial reporting and may identify additional material weaknesses in the 2017 Annual Report Form 10-K.future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our periodic reporting obligations.
In connection with a review of our financial statements for the three months ended June 30, 2019, we identified a material weakness in allocation of our intra-period adjustments to deferred income tax expense. We have determined that the design and operation of the controls over our income tax accounting process related to the review and analysis of the allocation of intra-period adjustments to deferred income tax expense resulting from significant, unusual and infrequent transactions were not effective. A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
Although this material weakness did not result in a material misstatement to our consolidated financial statements for the quarter ended June 30, 2019 or for any prior period, this material weakness could result in a misstatement of income tax expense for interim periods that, if not remediated, could result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.
With oversight from the Audit Committee, we intend to take the necessary steps to remediate the material weakness by enhancing our internal controls to ensure proper review by and communication between our external tax advisors and internal accounting personnel. Our efforts will consist primarily of strengthening our tax organization through continuing education and designing controls related to the components of our income tax process to enhance our management review controls over income taxes.
The material weakness described above or any newly identified material weakness could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. We cannot assure you that any measures we may take will be sufficient to remediate the control deficiencies that led to the material weakness in our internal control over financial reporting described above or to avoid potential future material weaknesses.
Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. If we are unable to successfully remediate our existing or any future material weakness in our internal control over financial reporting, or identify any additional material weaknesses that may exist, the accuracy and timing of our financial reporting may be adversely affected, we may be unable to maintain compliance with securities law requirements regarding timely filing of periodic reports in addition to applicable stock exchange listing requirements, we may be unable to prevent fraud, investors may lose confidence in our financial reporting, and our stock price may decline as a result.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
None.Not applicable.
Item 5. Other Information.
None.
Item 6. Exhibits.
The following exhibits in this index are required by Item 601 of Regulation S-K and are filed herewith or are incorporated herein by reference:
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3.1 | |
3.2 | |
10.110.1+ | ThirdSecond Amendment to First Amended and Restated Senior Secured Revolving Credit Agreement dated as of April 20, 2018, by and amongthe SilverBow Resources, Inc., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and certain lenders party thereto 2016 Equity Incentive Plan effective April 2, 2019 (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.'s Current Report on’s Form 8-K filed April 25, 2018,May 22, 2019, File No. 001-08754)00108754)..
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10.210.2+ | First Amendment to Note PurchaseEmployment Agreement, datedeffective as of April 20, 2018,2, 2019, by and amongbetween SilverBow Resources, Inc., as issuer, U.S. Bank National Association, as agent and collateral agent, the guarantors party thereto and the purchasers party theretoSean C. Woolverton (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.'s Current Report on’s Form 8-K filed April 25, 2018,8, 2019, File No. 001-08754). |
10.3+ | |
10.4+ |
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10.5+ |
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10.6+* |
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10.7+* |
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10.8+* |
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31.1* | |
31.2* | |
32*#32.1# | |
101.INS* | XBRL Instance Document |
101.SCH* | XBRL Schema Document |
101.CAL* | XBRL Calculation Linkbase Document |
101.LAB* | XBRL Label Linkbase Document |
101.PRE* | XBRL Presentation Linkbase Document |
101.DEF* | XBRL Definition Linkbase Document |
*Filed herewith
+Management contract or compensatory plan or arrangement
# Furnished herewith. Not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
+ Management contract or compensatory plan or arrangement.
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.
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| | | | |
| | | SILVERBOW RESOURCES, INC. (Registrant) |
Date: | August 8, 20189, 2019 | | By: | /s/ G. Gleeson Van Riet |
| | | | G. Gleeson Van Riet Executive Vice President and Chief Financial Officer |
| | | | |
Date: | August 8, 20189, 2019 | | By: | /s/ Gary G. Buchta |
| | | | Gary G. Buchta Controller |