Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 20, 2019 | Jun. 29, 2018 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | SANDRIDGE ENERGY INC | ||
Entity Central Index Key | 1,349,436 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Amendment Flag | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 539.2 | ||
Entity Common Stock, Shares Outstanding | 35,687,601 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 17,660 | $ 99,143 |
Restricted cash - other | 1,985 | 2,165 |
Accounts receivable, net | 45,503 | 71,277 |
Derivative contracts | 5,286 | 1,310 |
Prepaid expenses | 2,628 | 5,248 |
Other current assets | 265 | 15,954 |
Total current assets | 73,327 | 195,097 |
Oil and natural gas properties, using full cost method of accounting | ||
Proved | 1,269,091 | 1,056,806 |
Unproved | 60,152 | 100,884 |
Less: accumulated depreciation, depletion and impairment | (580,132) | (460,431) |
Net oil and natural gas properties capitalized costs | 749,111 | 697,259 |
Other property, plant and equipment, net | 200,838 | 225,981 |
Other assets | 1,062 | 1,290 |
Total assets | 1,024,338 | 1,119,627 |
Current liabilities | ||
Accounts payable and accrued expenses | 111,797 | 139,155 |
Derivative contracts | 0 | 10,627 |
Asset retirement obligations | 25,393 | 41,017 |
Other current liabilities | 0 | 8,115 |
Total current liabilities | 137,190 | 198,914 |
Long-term debt | 0 | 37,502 |
Derivative contracts | 0 | 3,568 |
Asset retirement obligations | 34,671 | 36,527 |
Other long-term obligations | 4,756 | 3,176 |
Total liabilities | 176,617 | 279,687 |
Commitments and contingencies (Note 13) | ||
Stockholders’ Equity | ||
Common stock, $0.001 par value; 250,000 shares authorized; 35,687 issued and outstanding at December 31, 2018 and 35,650 issued and outstanding at December 31, 2017 | 36 | 36 |
Warrants | 88,516 | 88,500 |
Additional paid-in capital | 1,055,164 | 1,038,324 |
Accumulated deficit | (295,995) | (286,920) |
Total stockholders’ equity | 847,721 | 839,940 |
Total liabilities and stockholders’ equity | $ 1,024,338 | $ 1,119,627 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common Stock, Shares Authorized | 250,000,000 | 250,000,000 |
Common stock, issued (in shares) | 35,687,000 | 35,650,000 |
Common stock, outstanding (in shares) | 35,687,000 | 35,650,000 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Revenues | ||||
Total revenues | $ 98,456 | $ 349,395 | $ 357,299 | |
Expenses | ||||
Production | 24,997 | 92,703 | 102,728 | |
Production taxes | 2,643 | 19,470 | 13,644 | |
Depreciation and depletion—oil and natural gas | 36,061 | 127,281 | 118,035 | |
Depreciation and amortization—other | 3,922 | 11,982 | 13,852 | |
Impairment | 319,087 | 4,170 | 4,019 | |
General and administrative | 9,837 | 41,666 | 76,024 | |
Accelerated vesting of employment compensation | 0 | 6,545 | 0 | |
Proxy contest | 0 | 7,139 | 0 | |
Terminated merger costs | 0 | 0 | 8,162 | |
Employee termination benefits | 12,334 | 32,657 | 4,815 | |
Loss (gain) on derivative contracts | 25,652 | 17,155 | (24,090) | |
Loss on settlement of contract | 0 | 0 | 0 | |
Other operating (income) expense | 268 | (998) | 479 | |
Total expenses | 434,801 | 359,770 | 317,668 | |
(Loss) income from operations | (336,345) | (10,375) | 39,631 | |
Other (expense) income | ||||
Interest expense | (372) | (2,787) | (3,868) | |
Gain on extinguishment of debt | 0 | 1,151 | 0 | |
Gain on reorganization items, net | 0 | 0 | 0 | |
Other income, net | 2,744 | 2,865 | 2,550 | |
Total other income (expense) | 2,372 | 1,229 | (1,318) | |
(Loss) income before income taxes | (333,973) | (9,146) | 38,313 | |
Income tax (benefit) expense | 9 | (71) | (8,749) | |
Net (loss) income | (333,982) | (9,075) | 47,062 | |
Preferred stock dividends | 0 | 0 | 0 | |
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders | $ (333,982) | $ (9,075) | $ 47,062 | |
(Loss) earnings per share | ||||
Basic (in dollars per share) | $ (17.61) | $ (0.26) | $ 1.45 | |
Diluted (in dollars per share) | $ (17.61) | $ (0.26) | $ 1.44 | |
Weighted average number of common shares outstanding | ||||
Basic (in shares) | 18,967 | 35,057 | 32,442 | |
Diluted (in shares) | 18,967 | 35,057 | 32,663 | |
Successor | Oil, natural gas and NGL | ||||
Revenues | ||||
Total revenues | $ 98,307 | $ 348,726 | $ 356,210 | |
Successor | Other | ||||
Revenues | ||||
Total revenues | $ 149 | $ 669 | $ 1,089 | |
Predecessor | ||||
Revenues | ||||
Total revenues | $ 293,809 | |||
Expenses | ||||
Production | 129,608 | |||
Production taxes | 6,107 | |||
Depreciation and depletion—oil and natural gas | 90,978 | |||
Depreciation and amortization—other | 21,323 | |||
Impairment | 718,194 | |||
General and administrative | 116,091 | |||
Accelerated vesting of employment compensation | 0 | |||
Proxy contest | 0 | |||
Terminated merger costs | 0 | |||
Employee termination benefits | 18,356 | |||
Loss (gain) on derivative contracts | 4,823 | |||
Loss on settlement of contract | 90,184 | |||
Other operating (income) expense | 4,348 | |||
Total expenses | 1,200,012 | |||
(Loss) income from operations | (906,203) | |||
Other (expense) income | ||||
Interest expense | (126,099) | |||
Gain on extinguishment of debt | 41,179 | |||
Gain on reorganization items, net | 2,430,599 | |||
Other income, net | 1,332 | |||
Total other income (expense) | 2,347,011 | |||
(Loss) income before income taxes | 1,440,808 | |||
Income tax (benefit) expense | 11 | |||
Net (loss) income | 1,440,797 | |||
Preferred stock dividends | 16,321 | |||
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders | $ 1,424,476 | |||
(Loss) earnings per share | ||||
Basic (in dollars per share) | $ 2.01 | |||
Diluted (in dollars per share) | $ 2.01 | |||
Weighted average number of common shares outstanding | ||||
Basic (in shares) | 708,928 | |||
Diluted (in shares) | 708,928 | |||
Predecessor | Oil, natural gas and NGL | ||||
Revenues | ||||
Total revenues | $ 279,971 | |||
Predecessor | Other | ||||
Revenues | ||||
Total revenues | $ 13,838 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Stockholders Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands | Total | Convertible Perpetual Preferred Stock | Common Stock | Warrants | Additional Paid-In Capital | Treasury Stock | Accumulated Deficit | Non-controlling Interest |
Beginning Balance (in shares) (Predecessor) at Dec. 31, 2015 | 5,420 | |||||||
Beginning Balance (in shares) (Predecessor) at Dec. 31, 2015 | 633,471 | |||||||
Beginning Balance (Predecessor) at Dec. 31, 2015 | $ (1,187,733) | $ 6 | $ 630 | $ 5,299,886 | $ (5,742) | $ (6,992,697) | $ 510,184 | |
Increase (Decrease) in Stockholders' Equity | ||||||||
Common stock issued for debt (in shares) | Predecessor | 84,390 | |||||||
Common stock issued for debt | Predecessor | 4,409 | $ 84 | 4,325 | |||||
Stock distributions, net of purchases - retirement plans (in shares) | Predecessor | 603 | |||||||
Stock distributions, net of purchases - retirement plans | Predecessor | (336) | (860) | 524 | |||||
Stock-based compensation | Predecessor | 11,102 | 11,102 | ||||||
Cash paid for tax withholdings on vested stock awards | Predecessor | (44) | (44) | ||||||
Cancellations of restricted stock awards, net (in shares) | Predecessor | (2,184) | |||||||
Cancellations of restricted stock awards, net of issuance | Predecessor | 0 | $ 2 | (2) | |||||
Common stock issued for conversion of securities (in shares) | Predecessor | (173) | 2,220 | ||||||
Common stock issued for conversion of securities | Predecessor | 0 | $ 2 | (2) | |||||
Net (loss) income | Predecessor | 1,440,797 | 1,440,797 | ||||||
Convertible perpetual preferred stock dividends | Predecessor | (16,321) | (16,321) | ||||||
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016 | 0 | |||||||
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016 | 0 | 0 | ||||||
Ending Balance (in shares) (Successor) at Oct. 01, 2016 | 18,932 | 6,442 | ||||||
Ending Balance (Predecessor) at Oct. 01, 2016 | 0 | $ 0 | $ 0 | $ 0 | 0 | 0 | 0 | 0 |
Ending Balance (Successor) at Oct. 01, 2016 | 827,424 | $ 19 | $ 88,382 | 739,023 | 0 | |||
Beginning Balance (in shares) (Predecessor) at Sep. 30, 2016 | 5,247 | |||||||
Beginning Balance (in shares) (Predecessor) at Sep. 30, 2016 | 718,500 | |||||||
Beginning Balance (Predecessor) at Sep. 30, 2016 | (1,250) | $ 6 | $ 718 | 5,314,405 | (5,218) | (5,311,140) | (21) | |
Increase (Decrease) in Stockholders' Equity | ||||||||
Issuance of common stock (in shares) | Predecessor | 18,932 | |||||||
Issuance of common stock | Predecessor | 575,163 | $ 19 | 575,144 | |||||
Issuance of Successor warrants (in shares) | Predecessor | 6,442 | |||||||
Issuance of Successor warrants | Predecessor | 88,382 | $ 88,382 | ||||||
Convertible note premium | Predecessor | 163,879 | 163,879 | ||||||
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016 | 0 | |||||||
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016 | 0 | 0 | ||||||
Ending Balance (in shares) (Successor) at Oct. 01, 2016 | 18,932 | 6,442 | ||||||
Ending Balance (Predecessor) at Oct. 01, 2016 | 0 | $ 0 | $ 0 | $ 0 | 0 | 0 | 0 | 0 |
Ending Balance (Successor) at Oct. 01, 2016 | 827,424 | $ 19 | 88,382 | 739,023 | 0 | |||
Increase (Decrease) in Stockholders' Equity | ||||||||
Cancellation of Predecessor equity (in shares) | Predecessor | (5,247) | (718,500) | ||||||
Cancellation of Predecessor equity | Predecessor | 1,250 | $ (6) | $ (718) | (5,314,405) | $ 5,218 | 5,311,140 | $ 21 | |
Issuance of stock awards, net of cancellations (in shares) | Successor | 10 | |||||||
Issuance of stock awards, net of cancellations | Successor | 0 | $ 0 | 0 | |||||
Common stock issued for debt (in shares) | Successor | 693 | |||||||
Common stock issued for debt | Successor | 13,001 | $ 1 | 13,000 | |||||
Stock-based compensation | Successor | 6,581 | 6,581 | ||||||
Cash paid for tax withholdings on vested stock awards | Successor | (110) | (110) | ||||||
Common stock issued for conversion of securities | Successor | 3 | $ (1) | 4 | |||||
Net (loss) income | Successor | (333,982) | (333,982) | ||||||
Ending Balance (in shares) (Successor) at Dec. 31, 2016 | 19,635 | 6,442 | ||||||
Ending Balance (Successor) at Dec. 31, 2016 | 512,917 | $ 20 | $ 88,381 | 758,498 | (333,982) | |||
Increase (Decrease) in Stockholders' Equity | ||||||||
Issuance of stock awards, net of cancellations (in shares) | Successor | 1,583 | |||||||
Issuance of stock awards, net of cancellations | Successor | 0 | $ 2 | (2) | |||||
Common stock issued for debt (in shares) | Successor | 14,328 | |||||||
Common stock issued for debt | Successor | 268,779 | $ 14 | 268,765 | |||||
Stock-based compensation | Successor | 17,912 | 17,912 | ||||||
Cash paid for tax withholdings on vested stock awards | Successor | (6,730) | (6,730) | ||||||
Issuance of common stock (in shares) | Successor | 104 | |||||||
Issuance of common stock | Successor | 0 | |||||||
Net (loss) income | Successor | 47,062 | 47,062 | ||||||
Issuance of Successor warrants (in shares) | Successor | 128 | |||||||
Issuance of Successor warrants | Successor | $ 0 | $ 119 | (119) | |||||
Ending Balance (in shares) (Successor) at Dec. 31, 2017 | 35,650 | 6,570 | ||||||
Ending Balance (in shares) at Dec. 31, 2017 | 35,650 | |||||||
Ending Balance (Successor) at Dec. 31, 2017 | $ 839,940 | $ 36 | $ 88,500 | 1,038,324 | (286,920) | |||
Increase (Decrease) in Stockholders' Equity | ||||||||
Issuance of stock awards, net of cancellations (in shares) | Successor | 9 | |||||||
Issuance of stock awards, net of cancellations | Successor | 0 | $ 0 | 0 | |||||
Common stock issued for debt | Successor | 0 | |||||||
Stock-based compensation | Successor | 24,276 | 24,276 | ||||||
Cash paid for tax withholdings on vested stock awards | Successor | (7,420) | (7,420) | ||||||
Issuance of common stock (in shares) | Successor | 28 | |||||||
Issuance of common stock | Successor | 0 | |||||||
Net (loss) income | Successor | (9,075) | (9,075) | ||||||
Issuance of Successor warrants (in shares) | Successor | 34 | |||||||
Issuance of Successor warrants | Successor | $ 0 | $ 16 | (16) | |||||
Ending Balance (in shares) (Successor) at Dec. 31, 2018 | 35,687 | 6,604 | ||||||
Ending Balance (in shares) at Dec. 31, 2018 | 35,687 | |||||||
Ending Balance (Successor) at Dec. 31, 2018 | $ 847,721 | $ 36 | $ 88,516 | $ 1,055,164 | $ (295,995) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Net (loss) income | $ (333,982) | $ (9,075) | $ 47,062 | |
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities | ||||
Provision for doubtful accounts | (13,166) | (462) | 406 | |
Depreciation, depletion and amortization | 39,983 | 139,263 | 131,887 | |
Impairment | 319,087 | 4,170 | 4,019 | |
Gain on reorganization items, net | 0 | 0 | 0 | |
Debt issuance costs amortization | 0 | 470 | 430 | |
Amortization of discount, net of premium, on debt | (81) | (47) | (330) | |
Gain on extinguishment of debt | 0 | (1,151) | 0 | |
Gain on debt derivatives | 0 | 0 | 0 | |
Cash paid for early conversion of convertible notes | 0 | 0 | 0 | |
Loss (gain) on derivative contracts | 25,652 | 17,155 | (24,090) | |
Cash (paid) received on settlement of derivative contracts | 7,698 | (35,325) | 7,260 | |
Loss on settlement of contract | 0 | 0 | 0 | |
Cash paid on settlement of contract | 0 | 0 | 0 | |
Stock-based compensation | 6,250 | 23,377 | 15,750 | |
Other | 717 | (1,571) | 344 | |
Changes in operating assets and liabilities increasing (decreasing) cash | ||||
Deconsolidation of noncontrolling interest | 0 | 0 | 0 | |
Receivables | 12,872 | 16,560 | 115 | |
Prepaid expenses | (1,079) | 2,620 | 127 | |
Other current assets | (260) | 170 | 191 | |
Other assets and liabilities, net | 1,505 | (1,754) | 4,186 | |
Accounts payable and accrued expenses | 990 | (4,257) | (2,199) | |
Asset retirement obligations | (591) | (4,629) | (3,979) | |
Net cash provided by (used in) operating activities | 65,595 | 145,514 | 181,179 | |
CASH FLOWS FROM INVESTING ACTIVITIES | ||||
Capital expenditures for property, plant and equipment | (51,676) | (187,047) | (219,246) | |
Acquisitions of assets | 0 | (24,764) | (48,312) | |
Proceeds from sale of assets | 11,841 | 28,358 | 21,834 | |
Net cash used in investing activities | (39,835) | (183,453) | (245,724) | |
CASH FLOWS FROM FINANCING ACTIVITIES | ||||
Proceeds from borrowings | 0 | 10,000 | 0 | |
Repayments of borrowings | (414,954) | (46,304) | 0 | |
Debt issuance costs | 0 | 0 | (1,488) | |
Proceeds from building mortgage | 0 | 0 | 0 | |
Payment of mortgage proceeds and cash recovery to debt holders | 0 | 0 | 0 | |
Cash paid for tax withholdings on vested stock awards | (110) | (7,420) | (6,730) | |
Other | 3 | 0 | 0 | |
Net cash (used in) provided by financing activities | (415,061) | (43,724) | (8,218) | |
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | (389,301) | (81,663) | (72,763) | |
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 563,372 | 101,308 | 174,071 | |
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year | 174,071 | $ 563,372 | $ 19,645 | $ 101,308 |
Predecessor | ||||
Net (loss) income | 1,440,797 | |||
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities | ||||
Provision for doubtful accounts | 16,704 | |||
Depreciation, depletion and amortization | 112,301 | |||
Impairment | 718,194 | |||
Gain on reorganization items, net | (2,442,436) | |||
Debt issuance costs amortization | 4,996 | |||
Amortization of discount, net of premium, on debt | 2,734 | |||
Gain on extinguishment of debt | (41,179) | |||
Gain on debt derivatives | (1,324) | |||
Cash paid for early conversion of convertible notes | (33,452) | |||
Loss (gain) on derivative contracts | 4,823 | |||
Cash (paid) received on settlement of derivative contracts | 72,608 | |||
Loss on settlement of contract | 90,184 | |||
Cash paid on settlement of contract | (11,000) | |||
Stock-based compensation | 9,075 | |||
Other | (3,260) | |||
Changes in operating assets and liabilities increasing (decreasing) cash | ||||
Deconsolidation of noncontrolling interest | (9,654) | |||
Receivables | 36,116 | |||
Prepaid expenses | (5,681) | |||
Other current assets | (181) | |||
Other assets and liabilities, net | (7,542) | |||
Accounts payable and accrued expenses | (3,595) | |||
Asset retirement obligations | (61,305) | |||
Net cash provided by (used in) operating activities | (112,077) | |||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||
Capital expenditures for property, plant and equipment | (186,452) | |||
Acquisitions of assets | (1,328) | |||
Proceeds from sale of assets | 20,090 | |||
Net cash used in investing activities | (167,690) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||
Proceeds from borrowings | 489,198 | |||
Repayments of borrowings | (74,243) | |||
Debt issuance costs | (333) | |||
Proceeds from building mortgage | 26,847 | |||
Payment of mortgage proceeds and cash recovery to debt holders | (33,874) | |||
Cash paid for tax withholdings on vested stock awards | (44) | |||
Other | 0 | |||
Net cash (used in) provided by financing activities | 407,551 | |||
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | 127,784 | |||
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | $ 563,372 | 435,588 | ||
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year | $ 563,372 |
Voluntary Reorganization under
Voluntary Reorganization under Chapter 11 Proceedings | 12 Months Ended |
Dec. 31, 2018 | |
Reorganizations [Abstract] | |
Voluntary Reorganization under Chapter 11 Proceedings | Voluntary Reorganization under Chapter 11 Proceedings On May 16, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on the Emergence Date. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through October 4, 2016. As such, the Company’s bankruptcy proceedings and related matters have been summarized below. The Company was able to conduct normal business activities and pay associated obligations for the period following its bankruptcy filing and was authorized to pay and has paid certain pre-petition obligations, including employee wages and benefits, goods and services provided by certain vendors, transportation of the Company’s production, royalties and costs incurred on the Company’s behalf by other working interest owners. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court. Automatic Stay. Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to settlement under the Bankruptcy Code. Plan of Reorganization. In accordance with the plan of reorganization confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on October 4, 2016: • First Lien Credit Agreement. All outstanding obligations under the senior credit facility were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0 million in cash and (b) participation in the newly established $425.0 million First Lien Exit Facility. Refer to Note 10 for additional information. • Cash Collateral Account. The Company deposited $50.0 million of cash in a Cash Collateral Account. This deposit was released to the Company in February 2017 in conjunction with the refinancing of the First Lien Exit Facility. • Senior Secured Notes . All outstanding obligations under the Senior Secured Notes were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of Common Stock issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued Convertible Notes, which mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017. Refer to Note 10 for additional information. • General Unsecured Claims. The Company’s general unsecured claims, including the Unsecured Notes, became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants, 4.5 million issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million issued immediately upon emergence. Refer to Note 14 for additional information. • Building Note . The Building Note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence Date), was issued and purchased on the Emergence Date for $26.8 million in cash, net of certain fees and expenses, by certain holders of the Senior Unsecured Notes. Proceeds received from the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan. Refer to Note 10 for additional information. • Preferred and Common Stock. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Summary of Significant Accounting Policies | |
Summary of Significant Accounting Policies | Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States. Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company proportionately consolidates the activities of the Royalty Trusts. Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly. Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. Restricted Cash. The Company maintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan. Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts. Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements. Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary. Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 11 for further discussion of the Company’s derivatives. Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Successor Company capitalized gross internal costs of $8.8 million, $14.8 million and $4.0 million during the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $22.7 million to the full cost pool during the Predecessor 2016 Period. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center. Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 8 for further discussion of impairments. Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During the year ended December 31, 2018 the Company capitalized an insignificant amount of interest costs and in the year ended December 31, 2017, and the Successor 2016 Period, the Company did not capitalize any interest costs as capital expenditures were not financed with debt during these periods. During the Predecessor 2016 Period, the Company capitalized interest of approximately $2.2 million on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt. Investments. Investments in marketable equity securities at December 31, 2017 related to the Company’s then-outstanding non-qualified deferred compensation plan. The investments in this plan were designated as available for sale and measured at fair value using quoted prices readily available in the market (fair value option) which requires unrealized gains and losses be reported in earnings. Investments are included in other current assets and other assets in the accompanying consolidated balance sheet at December 31, 2017. The non-qualified deferred compensation plan was terminated and all remaining assets were paid to participants during the first quarter of 2018. See Note 5 and Note 16 for additional discussion of investments. Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 12 for further discussion of the Company’s asset retirement obligations. Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company made an accounting policy election on the Emergence Date to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $27.7 million, $29.1 million and $7.4 million of transportation costs as a reduction from revenues in the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, versus presenting $26.2 million of these costs as production expenses in the Predecessor 2016 Period. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See Note 17 for further information on the Company's accounting policies related to revenues. The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions of $1.7 million and $1.6 million at December 31, 2018 and 2017, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets. Allocation of Share-Based Compensation. For both the Successor and Predecessor Companies, equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations. Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense. Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards and warrants, using the treasury method, and convertible senior notes, using the if-converted method. Potentially dilutive securities for the Predecessor Company consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. During the Successor 2016 Period, the Company assumed the conversion of the Convertible Notes to common stock under the if-converted method and determined if it was more dilutive than including the expense associated with the Convertible Notes in the computation of income available to common stockholders during the period the Convertible Notes were outstanding. The Predecessor Company also assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock under the if-converted method and determined if it was more dilutive than including the preferred stock dividends or expense associated with the Convertible Senior Unsecured Notes, respectively, in the computation of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 21 for the Company’s earnings per share calculation. Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 13 for discussion of the Company’s commitments and contingencies. Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected. Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces. The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2018 - Successor Targa Midstream Services L.P. $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 - Successor Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % Period from October 2, 2016 through December 31, 2016 - Successor Targa Pipeline Mid-Continent West OK LLC $ 35,845 36.4 % Plains Marketing, L.P. $ 32,022 32.5 % Period from January 1, 2016 through October 1, 2016 - Predecessor Plains Marketing, L.P. $ 110,370 37.6 % Targa Pipeline Mid-Continent West OK LLC $ 108,238 36.8 % Recent Accounting Pronouncements. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenues from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 to January 1, 2018, for the Company. The ASU required adoption using either the retrospective transition method, which required restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company adopted Topic 606 and all the related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 17 for further discussion of the adoption of the new revenue standard. The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory,” which removed the prohibition in ASC 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption. The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption. The FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the disclosure Requirements for Fair Value Measurement," which removes, modifies or adds disclosure requirements regarding fair value measurements. The amendments in this ASU are effective for all entities beginning after December 15, 2019, with amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty requiring prospective adoption and all other amendments requiring retrospective adoption. Early adoption is permitted and the Company elected to adopt this ASU during the third quarter of 2018, which resulted in a change to the Company's fair value measurement disclosures on a prospective basis, but had no impact on its consolidated financial statements. Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” and other associated ASU's related to Topic 842 which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. This topic is effective for the Company on January 1, 2019. Early adoption is permitted. Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ and therefore will not have to reassess its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company will also utilize the short-term lease recognition exemption, which means assets and liabilities will not be recognized for the rights and obligations of qualifying leases, including existing short-term leases of those assets in transition. The Company does not plan to elect the use-of-hindsight. Upon adoption, the Company anticipates (i) recognizing assets and liabilities for the rights and obligations of its vehicle and equipment leases and, (ii) providing new disclosures about the Company’s leasing activities. The Company has completed the implementation of a lease contract management system and is finalizing processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases on and after the date of adoption. The Company will adopt Topic 842 using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company is still finalizing its evaluation of the January 1, 2019 adoption. The impact to recognize the assets and liabilities for the rights and obligations of the Company's leases on the balance sheet is not expected to be material at adoption. New disclosures will be required in the first quarter of 2019 to present information related to the Company's leases, including the Company's short-term leases, which are not required to be presented on the balance sheet utilizing the short-term lease recognition exemption. |
Revaluation of Assets | |
Summary of Significant Accounting Policies | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Fresh Start Accounting. Upon emergence from bankruptcy, the Company applied fresh start accounting to its financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims. The Company elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of its normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2016, and October 4, 2016, were immaterial and use of an accounting convenience date of October 1, 2016, was appropriate. As such, related fresh start adjustments are included in the accompanying statement of operations for the Predecessor 2016 Period. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the Successor 2016 Period will not be comparable with the financial statements prior to that date. Reorganization Value. Reorganization value represented the fair value of the Successor Company’s total assets on the Emergence Date and approximated the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company’s reorganization value was derived from an estimate of enterprise value, which represented the estimated fair value of long-term debt and other interest-bearing liabilities and shareholders’ equity. In support of the Plan, the Company estimated the enterprise value of the Successor Company to be in the range of $1.0 billion to $1.3 billion, which was subsequently approved by the Bankruptcy Court. The Company estimated the final enterprise value to be approximately $1.1 billion. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections, third-party real estate reports, and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date (in thousands): Enterprise value $ 1,089,808 Plus: cash and cash equivalents 563,372 Plus: other working capital liabilities 131,766 Plus: other long-term liabilities 8,549 Reorganization value of Successor assets $ 1,793,495 Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized. Reorganization Items Reorganization items represent liabilities settled, net of amounts incurred, subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as gain on reorganization items, net in the accompanying consolidated statement of operations. The following table summarizes reorganization items for the Predecessor 2016 Period (in thousands): Unamortized long-term debt $ 3,546,847 Litigation claims (20,478) Rejections and cures of executory contracts (16,038) Ad valorem and franchise taxes (3,494) Legal and professional fees and expenses (44,920) Write off of director and officer insurance policy (7,533) Gain on accounts payable settlements 84,228 Loss on mortgage (8,153) Gain on preferred stock dividends 37,893 Fresh start valuation adjustments (28,549) Fair value of equity issued (827,424) Principal value of Convertible Notes issued (281,780) Gain on reorganization items, net $ 2,430,599 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Supplemental Disclosure of Cash Flow Information Cash paid for reorganization items $ — $ — $ — $ (55,606) Cash paid for interest, net of amounts capitalized $ (4,045) $ (2,438) $ (1,183) $ (104,609) Cash received (paid) for income taxes $ 4,381 $ 4,348 $ — $ (28) Supplemental Disclosure of Noncash Investing and Financing Activities Cumulative effect of adoption of ASU 2015-02 $ — $ — $ — $ (247,566) Property, plant and equipment transferred in settlement of contract $ — $ — $ — $ 215,635 Change in accrued capital expenditures $ (15,861) $ (28,999) $ 10,630 $ 25,045 Equity issued for debt $ — $ (268,779) $ (13,001) $ (4,409) |
Acquisitions and Divestitures o
Acquisitions and Divestitures of Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2018 | |
Acquisitions And Dispositions [Abstract] | |
Acquisitions and Divestitures of Oil and Gas Properties | Acquisitions and Divestitures of Oil and Gas Properties Successor Acquisitions and Divestitures 2018 Divestitures Divestiture of Permian Basin Properties. On November 1, 2018, the Company sold substantially all of its oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced its asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust included 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, the Company no longer has any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale. 2018 Acquisitions Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired an interest in certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which are operated by the Company, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime. 2017 Acquisitions Acquisition of Properties. On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage. 2017 Divestitures 2017 Property Divestitures. In 2017, the Company divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized. Predecessor Acquisitions and Divestitures 2016 Divestiture Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. In January 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental and was released from all past, current and future claims and obligations under an existing 30 year treating agreement between the companies. As of the date of the transaction, the Company had accrued approximately $111.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012. The Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced its asset retirement obligations associated with its oil and natural gas properties by $34.1 million. See Note 7 for discussion of non-oil and gas divestitures. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current and non-current assets, accounts payable and accrued expenses and other current liabilities included in the consolidated balance sheets approximated fair value at December 31, 2018, and December 31, 2017. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 7. Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3 Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources ( i.e., supported by little or no market activity). Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of these inputs requires judgment, which may affect the valuation and placement of these assets and liabilities within the fair value hierarchy levels. The market for the Company’s financial assets and liabilities, any associated credit risk and other factors are considered in calculating the fair values. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 2 of the hierarchy as of December 31, 2018, and Level 1 and Level 2 as of December 31, 2017, as described below. Level 1 Fair Value Measurements Investments. The fair value of investments, which consisted of assets held in the Company’s non-qualified deferred compensation plan, was based on quoted market prices. See Note 2 and Note 16 for additional information. Level 2 Fair Value Measurements Commodity Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates. Fair Value - Recurring Measurement Basis The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands): December 31, 2018 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,286 $ — $ — $ 5,286 $ — $ 5,286 $ — $ — $ 5,286 December 31, 2017 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,582 $ — (4,272) $ 1,310 Investments 5,072 — — — 5,072 $ 5,072 $ 5,582 $ — $ (4,272) $ 6,382 Liabilities Commodity derivative contracts $ — $ 18,467 $ — $ (4,272) $ 14,195 $ — $ 18,467 $ — $ (4,272) $ 14,195 ____________________ 1. Represents the impact of netting assets and liabilities with counterparties where the right of offset exists. Transfers. During the years ended December 31, 2018 and 2017, the Successor 2016 Period and Predecessor 2016 Period, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. Fair Value of Financial Instruments - Long-Term Debt The fair value of the Building Note was measured using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The Building Note was paid in full during the first quarter of 2018. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands): December 31, 2018 December 31, 2017 Fair Value Carrying Value Fair Value Carrying Value Building Note $ — $ — $ 42,526 $ 37,502 See Note 10 for discussion of the Company’s long-term debt. Fair Value of Non-Financial Assets and Liabilities See Note 8 for discussion of the Company’s impairment valuations. |
Accounts Receivable
Accounts Receivable | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Accounts Receivable | Accounts Receivable A summary of accounts receivable is as follows (in thousands): December 31, 2018 2017 Oil, natural gas and NGL sales $ 31,780 $ 35,301 Joint interest billing 13,083 29,505 Oil and natural gas services 604 639 Other 1,331 7,106 Total accounts receivable 46,798 72,551 Less: allowance for doubtful accounts (1,295) (1,274) Total accounts receivable, net $ 45,503 $ 71,277 The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning balance $ 1,274 $ 880 $ — $ 4,847 Additions charged to costs and expenses(1) 758 397 880 16,695 Deductions(2) (737) (3) — (751) Impact of fresh start accounting — — — (20,791) Ending balance $ 1,295 $ 1,274 $ 880 $ — ____________________ 1. The Predecessor 2016 Period includes a $16.7 million addition for a joint interest account receivable after determining that future collection was doubtful when the joint interest owner filed for bankruptcy. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment consists of the following (in thousands): December 31, 2018 2017 Oil and natural gas properties Proved $ 1,269,091 $ 1,056,806 Unproved 60,152 100,884 Total oil and natural gas properties 1,329,243 1,157,690 Less accumulated depreciation, depletion and impairment (580,132) (460,431) Net oil and natural gas properties capitalized costs 749,111 697,259 Land 4,400 4,500 Electrical infrastructure 131,176 131,010 Non-oil and natural gas equipment 13,458 26,809 Buildings and structures 77,148 79,548 Total 226,182 241,867 Less accumulated depreciation and amortization (25,344) (15,886) Other property, plant and equipment, net 200,838 225,981 Total property, plant and equipment, net $ 949,949 $ 923,240 The average rates used for depreciation and depletion of oil and natural gas properties were $10.32 per Boe in 2018, $7.92 per Boe in 2017, $8.31 per Boe in the Successor 2016 Period and $6.05 per Boe in the Predecessor 2016 Period. See Note 8 for discussion of impairment of other property, plant and equipment. The Company had approximately $10.6 million in assets classified as held for sale in the other current assets line of the accompanying consolidated balance sheet at December 31, 2017. Approximately $9.3 million of this total was related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and sold during the second quarter of 2018 for a net amount of approximately $10.4 million, including transaction fees. The resulting gain of $1.1 million was recorded in other operating expense on the accompanying condensed consolidated statements of operations for the year ended December 31, 2018. Additionally, during the first quarter of 2018, the Company classified its remaining midstream generator assets as held for sale. These assets had a carrying value of $5.7 million which exceeded the estimated net realizable value of $1.6 million based on expected sales prices obtained from third parties. As a result, the Company recorded an impairment of $4.1 million for the year ended December 31, 2018. The midstream generator assets were sold during the second quarter of 2018 with no gain or loss recognized on the sale. No significant assets were classified as held for sale at December 31, 2018. Costs Excluded from Amortization The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2018 (in thousands): Year Cost Incurred Total 2018 2017 2016 2015 and Prior Property acquisition $ 59,522 $ 3,859 $ 20,647 $ 13,735 $ 21,281 Exploration 630 13 323 243 51 Total costs incurred $ 60,152 $ 3,872 $ 20,970 $ 13,978 $ 21,332 For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three five |
Impairment
Impairment | 12 Months Ended |
Dec. 31, 2018 | |
Asset Impairment Charges [Abstract] | |
Impairment | Impairment The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. Estimated fair values of drilling, midstream, electrical transmission and other assets were determined in accordance with the policies discussed in Note 2. Impairment for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Full cost pool ceiling limitation(1)(2) $ — $ — $ 319,087 $ 657,392 Drilling assets(3)(4) 22 4,019 — 3,511 Electrical infrastructure assets(5) — — — 55,600 Midstream assets(6) 4,148 — — 1,691 $ 4,170 $ 4,019 $ 319,087 $ 718,194 ____________________ 1. Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting , whereby the fair value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment. 2. Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairment recorded in the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes. 3. Impairment recorded in the year s ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. 4. Impairment recorded in the Predecessor 2016 Period resulted from the write-down of certain drilling assets after the Company discontinued drilling operations in the Permian region. 5. Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage. 6. Im pairment recorded in 2018 reflects the write down of midstream generator assets classified as held for sale to the net realizable value. The impairment recorded in the Predecessor 2016 Period resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO 2 compressor station after determining that their future use was limited. |
Accounts Payable and Accrued Ex
Accounts Payable and Accrued Expenses | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Expenses | Accounts Payable and Accrued Expenses Accounts payable and accrued expenses consist of the following (in thousands): December 31, 2018 2017 Accounts payable and other accrued expenses $ 78,219 $ 90,423 Payroll and benefits 12,891 21,475 Production payable 12,767 18,059 Taxes payable 5,350 3,983 Drilling advances 2,031 3,830 Accrued interest 539 1,385 Total accounts payable and accrued expenses $ 111,797 $ 139,155 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt consists of the following (in thousands): December 31, 2018 2017 Credit facility $ — $ — Building Note — 37,502 Total debt — 37,502 Less: current maturities of long-term debt — — Long-term debt $ — $ 37,502 Credit Facility. On February 10, 2017, the Company's First Lien Exit Facility was refinanced and replaced by a new $600.0 million credit facility with a $425.0 million available borrowing base. The borrowing base under the credit facility was reduced from $425.0 million to $350.0 million during the October 2018 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. Outstanding borrowings under the credit facility bear interest based on a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (b) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50% on any available portion of the credit facility. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Upon refinancing of the First Lien Exit Facility, $50.0 million maintained in a restricted cash collateral account, as required by the terms of the First Lien Exit Facility, was released to the Company. The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all the Company's proved reserves included in the reserve report most recently provided to the lenders, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing). As of the end of each fiscal quarter, the credit facility requires the Company to maintain (i) a maximum consolidated total net leverage ratio of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. The Company was in compliance with all applicable financial covenants under the credit facility at the end of each fiscal quarter in 2018. The credit facility contains customary affirmative and negative covenants, including compliance with certain laws (including environmental laws, ERISA and anti-corruption laws), maintaining required insurance, delivering quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on incurring liens and indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. The Company was in compliance with these covenants as of December 31, 2018. The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving a liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods. Changes in the composition of the Company's Board resulting from the 2018 annual meeting in June 2018 may have been an event of default under the change in control provisions in the credit facility. However, the Company entered into a consent and waiver agreement with the administrative agent and certain lenders constituting the majority lenders under the credit facility. The consent and waiver agreement waived any event of default which might have occurred as a result of the change in the composition of the members of the Company’s Board and recognized the new members of the Board as existing members of the Board under the definition of change in control in the credit agreement. The Company had no amounts outstanding under the credit facility at December 31, 2018 and $5.2 million in outstanding letters of credit, which reduce availability under the credit facility on a dollar-for-dollar basis. First Lien Exit Facility. On the Emergence Date, the Company entered into the First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender. The First Lien Exit Facility had a borrowing base of $425.0 million and was set to mature on February 4, 2020. Outstanding borrowings bore interest at a rate equal to either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months. Quarterly commitment fees were assessed at annual rates of 0.50% on any available portion of the First Lien Exit Facility. The Company had the right to prepay loans under the First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Convertible Notes. As discussed in Note 1, on the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $281.8 million principal amount of Convertible Notes, which did not bear regular interest and were set to mature and mandatorily convert into shares of Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. Under fresh start accounting, the Convertible Notes were recorded at their fair value of $445.7 million, which resulted in a premium of $163.9 million being recorded to additional paid in capital. The Company’s obligations pursuant to the Convertible Notes were fully and unconditionally guaranteed, jointly and severally, by each of the guarantors of the First Lien Exit Facility. The Convertible Notes were initially convertible at a conversion rate of 0.05330841 shares of Common Stock per $1.00 principal amount of Convertible Notes, which represented, approximately 15.0 million total shares of common stock. The conversion rate was subject to customary anti-dilution adjustments. Convertible Notes holders could convert them at any time up to, and including, the business day prior to the maturity date. Between the Emergence Date and December 31, 2016, holders requested conversion of approximately $13.0 million of the Convertible Notes into approximately 0.7 million shares of Common Stock. Additionally, from January 1, 2017 to February 9, 2017, holders requested conversion of approximately $5.1 million of the Convertible Notes into approximately 0.3 million shares of Common Stock. The remaining $263.7 million par value of outstanding Convertible Notes mandatorily converted into 14.1 million shares of Common Stock when the First Lien Exit Facility was refinanced on February 10, 2017, after the determination by the Successor Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorable to the Company and (b) causing a conversion was not the primary purpose of the refinancing. Building Note . As discussed in Note 1, on the Emergence Date, the Company entered into the Building Note which had an initial principal amount of $35.0 million, and was set to mature on October 2, 2021. The Company sold the Building Note for net proceeds of $26.8 million which were then remitted to unsecured creditors on the Emergence Date. The Company repaid the Building Note in full in February 2018. Interest was payable on the Building Note at 6% per annum for the first year |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives Commodity Derivatives The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. On occasion, the Company has attempted to manage this risk on a portion of its forecasted oil or natural gas production sales through the use of commodity derivative contracts. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis. On a quarterly basis, the commodity derivative contract valuations are adjusted to the mark-to-market valuation. At December 31, 2018, the Company’s commodity derivative contracts consisted of natural gas fixed price swaps. The Company receives a fixed price for these contracts and pays a floating market price to the counterparty over a specified period for a contracted volume. The Company recorded loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018 and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all oil derivative contracts in December 2018. The Company recorded loss on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. The net receipts for the Predecessor 2016 Period include $17.9 million of cash receipts due to early settlements of certain derivative contracts after the Chapter 11 filings occurred. In December 2018, we entered into early settlements of all open crude oil swaps covering nine thousand bbls/day of production in December 2018 at an average strike price of $56.12, and five thousand bbls/day of production during 2019 at an average strike price of $54.29. Simultaneously, the Company entered into natural gas swaps for the first quarter of 2019. The Board and management of the Company are continuing to evaluate the futures market for oil and natural gas in an attempt to protect short-term cash flow and to mitigate exposure to adverse oil and natural gas price changes. Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis by commodity type in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2018, the counterparties to the Company’s open commodity derivative contracts consisted of four financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility. The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2018 and 2017 (in thousands): December 31, 2018 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,286 $ — $ 5,286 $ — $ 5,286 Total $ 5,286 $ — $ 5,286 $ — $ 5,286 December 31, 2017 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,582 $ (4,272) $ 1,310 $ — $ 1,310 Total $ 5,582 $ (4,272) $ 1,310 $ — $ 1,310 Liabilities Derivative contracts - current $ 14,899 $ (4,272) $ 10,627 $ (10,627) $ — Derivative contracts - noncurrent 3,568 — 3,568 (3,568) — Total $ 18,467 $ (4,272) $ 14,195 $ (14,195) $ — At December 31, 2018, the Company’s open commodity derivative contracts consisted of the following: Natural Gas Price Swaps Notional (MMcf) Weighted Average Fixed Price January 2019 - March 2019 4,500 $ 4.28 Fair Value of Derivatives The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands): December 31, December 31, Type of Contract Balance Sheet Classification 2018 2017 Derivative assets Natural gas price swaps Derivative contracts - current $ 5,286 $ 5,582 Derivative liabilities Oil price swaps Derivative contracts - current — (14,899) Oil price swaps Derivative contracts - noncurrent — (3,568) Total net derivative contracts $ 5,286 $ (12,885) See Note 5 for additional discussion of the fair value measurement of the Company’s derivative contracts. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning balance $ 77,544 $ 106,481 $ 92,413 $ 103,578 Liability incurred upon acquiring and drilling wells 7,079 1,336 121 505 Revisions in estimated cash flows(1) 870 (28,565) 12,397 — Liability settled or disposed in current period(2) (31,967) (11,308) (540) (36,979) Accretion 6,538 9,600 2,090 4,365 Impact of fresh start accounting — — — 20,944 Ending balance 60,064 77,544 106,481 92,413 Less: current portion 25,393 41,017 66,154 65,678 Asset retirement obligations, net of current $ 34,671 $ 36,527 $ 40,327 $ 26,735 ____________________ 1. Revisions for the year s ended December 31, 2018 and 2017, and the Successor 2016 Period relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates. 2. Liability settled or disposed for the year ended December 31, 2018 includes $26.9 million associated with the Permian Properties sold in November 2018. Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of the Company's various future commitments as of December 31, 2018. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. Third-party drilling rig agreements. As of December 31, 2018, the Company had third-party drilling rig agreements with various terms extending to May 2019 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2018 total approximately $3.6 million. Leases and other. As of December 31, 2018, the Company had commitments for leases and other agreements totaling approximately $4.8 million. These commitments are primarily for fleet vehicles, maintenance services, office equipment, and purchase obligations related to software services. Rental expense related to these leases was not significant for the years ended December 31, 2018, December 31, 2017, the Successor 2016 Period or the Predecessor 2016 Period. Litigation and Claims. As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016. Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”): • In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma • Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma • Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of Oklahoma On November 8, 2018, the court in the Gernandt case granted the defendants’ respective motions to dismiss and dismissed the action with prejudice. Although the remaining two Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time. The Company has not established any reserves relating to any of the Cases. In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust, for as long as the Trusts exist, against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Equity | Equity Successor Equity Common Stock and Performance Share Units. At December 31, 2018, the Company had 35.7 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.4 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. In accordance with normal practices, the Company granted additional restricted stock awards and an immaterial amount of performance share units in the third quarter of 2018. Warrants. The Company has issued approximately 4.6 million Series A warrants and 2.0 million Series B warrants to certain holders of general unsecured claims as defined in the Plan. These warrants are exercisable until October 4, 2022 for one share of common stock per warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the warrants. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. Poison Pill. On November 26, 2017, we entered into the Poison Pill. At our 2018 annual meeting in June 2018, the Poison Pill was terminated. Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired. Successor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Number of shares withheld for taxes 495 349 5 Value of shares withheld for taxes $ 7,420 $ 6,730 $ 110 Predecessor Equity Preferred Stock Dividends. Prior to the Chapter 11 petition filings, dividends on the Company’s 8.5% and 7.0% convertible perpetual preferred stock could be paid in cash or with shares of the Company’s common stock at the Company’s election. The Company suspended payment of the cumulative dividend on its 7.0% convertible perpetual preferred stock during the third quarter of 2015 and suspended the semi-annual dividend on its 8.5% convertible perpetual preferred stock prior to the February 2016 semi-annual dividend payment date . The Company ceased accruing dividends on its 8.5% and 7.0% convertible perpetual preferred stock as of May 16, 2016, in conjunction with the Chapter 11 petition filings. Preferred stock dividend accruals in arrears prior to the Emergence Date for the Predecessor Company’s 8.5% and 7.0% convertible perpetual preferred stock were as follows (in thousands): Predecessor Period from January 1, 2016 through October 1, 2016 8.5% Convertible perpetual preferred stock Dividends in arrears $ 11,262 7.0% Convertible perpetual preferred stock Dividends in arrears $ 21,000 Paid and unpaid dividends included in the calculation of income available to the Company’s common stockholders and the Company’s basic earnings per share calculation for the Predecessor 2016 Period are presented in the accompanying consolidated statements of operations. Preferred stock dividends in arrears were eliminated on the Emergence Date with no recovery paid to holders. See Note 21 for discussion of the Company’s (loss) earnings per share calculation. |
Share Based Compensation
Share Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-Based Compensation | Share-Based Compensation As discussed in Note 1, the Predecessor Company’s common stock was canceled and the Successor Company issued new Common Stock on the Emergence Date. Accordingly, the Predecessor Company's then existing share-based compensation awards were also canceled, which resulted in the recognition of $5.9 million in previously unamortized expense related to these awards on the date of cancellation. Share based compensation for the Predecessor and Successor periods are not comparable. Successor Share-Based Compensation Omnibus Incentive Plan. The Omnibus Incentive Plan became effective on the Emergence Date after the cancellation of the Predecessor Company’s share-based compensation awards. The Omnibus Incentive Plan authorizes the issuance of up to 4.6 million shares of SandRidge Common Stock. Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of Common Stock, as well as certain cash-based awards. At December 31, 2018, the Company had restricted stock awards and an immaterial amount of performance share units outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur. Restricted Stock Awards. The Successor Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s Common Stock on the date of grant. Vesting for certain restricted stock awards was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. The majority of the remaining restricted stock awards vested in June 2018 as a result of the accelerated vesting event related to the change in the composition of the Board resulting from the 2018 annual meeting discussed in Note 18. The Company granted additional restricted stock awards in the second half of 2018. Outstanding restricted shares will generally vest over either a one-year period or three-year period. The following table presents a summary of the Successor Company’s unvested restricted stock awards: Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at October 1, 2016 — $ — Granted 1,448 $ 24.32 Vested (14) $ 24.32 Forfeited / Canceled (27) $ 24.32 Unvested restricted shares outstanding at December 31, 2016 1,407 $ 24.32 Granted 671 $ 19.97 Vested (827) $ 23.23 Forfeited / Canceled (146) $ 23.52 Unvested restricted shares outstanding at December 31, 2017 1,105 $ 22.62 Granted 370 $ 16.00 Vested (1,066) $ 22.63 Forfeited / Canceled (44) $ 21.04 Unvested restricted shares outstanding at December 31, 2018 365 $ 16.07 As of December 31, 2018, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $4.7 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.2 years. The aggregate intrinsic value of restricted stock that vested during 2018 was approximately $16.0 million based on the stock price at the time of vesting. Performance Share Units. In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were settled in shares of the Company's common stock with one share of common stock being issued per performance share unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company's performance share units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance share units outstanding at December 31, 2016 — Granted 199 Vested — Forfeited / Canceled (16) Unvested performance share units outstanding at December 31, 2017 183 Granted 111 Vested (177) Forfeited / Canceled (6) Unvested performance share units outstanding at December 31, 2018 111 $ 20.41 The aggregate intrinsic value of performance share units that vested during the year ended December 31, 2018 was approximately $2.7 million based on the stock price at the time of vesting. Successor Incentive-Based Compensation Performance Units. In October 2016, the Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were paid at the issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a summary of the Company's performance units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance units outstanding at October 1, 2016 — Granted 97 Vested (1) Forfeited / Canceled (9) Unvested performance units outstanding at December 31, 2016 87 Granted — Vested (32) Forfeited / Canceled (6) Unvested performance units outstanding at December 31, 2017 49 Granted — Vested (48) Forfeited / Canceled (1) Unvested performance units outstanding at December 31, 2018 — — The aggregate intrinsic value of performance units that vested during the year ended December 31, 2018 was approximately $4.8 million. The following tables summarize the Successor Company's share and incentive-based compensation for the years ended December 31, 2018 and 2017, and the Successor 2016 Period (in thousands): Recurring Compensation Expense(1) Executive Terminations(2) Reduction in Force(2) Accelerated Vesting(3) Total Year Ended December 31, 2018 Equity-classified awards: Restricted stock awards $ 4,735 $ 8,140 $ 3,777 $ 5,181 $ 21,833 Performance share units 619 1,056 158 610 2,443 Total share-based compensation expense 5,354 9,196 3,935 5,791 24,276 Liability-classified awards: Performance units 756 2,151 558 1,309 4,774 Total share and incentive-based compensation expense 6,110 11,347 4,493 7,100 29,050 Less: Capitalized compensation expense (482) — — (555) (1,037) Share and incentive-based compensation expense, net $ 5,628 $ 11,347 $ 4,493 $ 6,545 $ 28,013 Year Ended December 31, 2017 Equity-classified awards: Restricted stock awards $ 14,731 $ 1,825 $ — $ — $ 16,556 Performance share units 1,356 — — — 1,356 Total share-based compensation expense 16,087 1,825 — — 17,912 Liability-classified awards: Performance units 2,574 — — — 2,574 Total share and incentive-based compensation expense 18,661 1,825 — — 20,486 Less: Capitalized compensation expense (2,521) — — — (2,521) Share and incentive-based compensation expense, net $ 16,140 $ 1,825 $ — $ — $ 17,965 Period from October 2, 2016 through December 31, 2016 Equity-classified awards: Restricted stock awards $ 2,296 $ — $ 4,285 $ — $ 6,581 Total share-based compensation expense 2,296 — 4,285 — 6,581 Liability-classified awards: Performance units 528 — 737 — 1,265 Total share and incentive-based compensation expense 2,824 — 5,022 — 7,846 Less: Capitalized compensation expense (407) — — — (407) Share and incentive-based compensation expense, net $ 2,417 $ — $ 5,022 $ — $ 7,439 ____________________ 1. Recorded in general and administrative expense in the accompanying consolidated statements of operations. 2. Recorded in employee termination benefits in the accompanying consolidated statements of operations. 3. Recorded in accelerated vesting of employment compensation in the accompanying consolidated statements of operations. Predecessor Share-Based Compensation Restricted Common Stock Awards. The Predecessor Company’s restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market value of the common stock on the date of grant. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards. Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at December 31, 2015 5,626 $ 4.85 Granted — $ — Vested (3,034) $ 5.34 Forfeited / Canceled (2,592) $ 4.31 Predecessor ending unvested restricted shares at October 1, 2016 — $ — The Predecessor Company issued share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the 2009 Plan. Total share-based compensation expense was measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards. The Predecessor Company recognized total share-based compensation expense of $11.2 million, of which $1.7 million was capitalized, for the Predecessor 2016 Period. Share-based compensation expense for the Predecessor 2016 Period includes $5.4 million for the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s outstanding unvested restricted stock units, performance units and performance share units during the Predecessor 2016 Period. |
Incentive and Deferred Compensa
Incentive and Deferred Compensation Plans | 12 Months Ended |
Dec. 31, 2018 | |
Compensation Related Costs [Abstract] | |
Incentive and Deferred Compensation Plans | Incentive and Deferred Compensation Plans Annual Incentive Plan. The Annual Incentive Plan ("AIP") incorporates quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2018 and 2017 performance years. Potential payout percentages ranged from 0% to 200% of specified target levels based on actual performance. Payment for the 2018 performance year will be made in the first quarter of 2019 based on actual performance as determined by the Board of Directors relative to the targets specified in the plan. As of December 31, 2018, the Company had accrued approximately $6.6 million for the 2018 AIP. Payment of $8.7 million was made in the first quarter of 2018 for the 2017 performance year. Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan which included long-term incentive awards, and provided for quarterly cash payments at a target percentage to participants based upon corporate performance goals with aggregate annual payout opportunity ranging from 0% to 200%. The first three quarterly cash payments were limited to no greater than target amounts with a cash make up payment in the first quarter of 2017 for actual performance based on the Company’s annual results. Under this plan, the Predecessor Company paid out approximately $17.8 million during the first two quarters of 2016 and the Successor Company paid out approximately $7.1 million during the fourth quarter of 2016 and approximately $15.8 million during the first quarter of 2017. 401(k) Plan. The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by IRS. For the years ended December 31, 2018, and 2017, the Successor 2016 Period and the Predecessor 2016 Period, the Company made matching contributions to the plan equal to 100% on the first 10% of employee deferred wages, excluding incentive compensation, totaling $2.8 million, $3.6 million, $0.9 million and $4.9 million, respectively. The decrease in contributions is due primarily to reductions in force that occurred in 2017 and 2018. Participants in the plan are immediately 100% vested in the discretionary employee contributions and related earnings on those contributions. The Company's matching contributions and related earnings vest based on years of service, with full vesting occurring on the fourth anniversary of employment. Deferred Compensation Plans. The Company maintained a non-qualified deferred compensation plan that allowed eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans through December 31, 2016. The Company made insignificant matching contributions on non-qualified contributions for the Successor 2016 Period and the Predecessor 2016 Period. On December 31, 2016, the Successor Company began the process of terminating the non-qualified deferred compensation plan and no employee or employer contributions were made to the plan after that date. In accordance with the plan termination procedures, the $5.1 million of remaining assets |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | Revenues The Company adopted the new revenue standard on January 1, 2018, using the modified retrospective method for all contracts outstanding on that date. Adoption of the new revenue standard had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date, and the Company does not expect any further material impact to its consolidated financial statements on an ongoing basis as a result of adopting the new revenue standard. The Company has included the disclosures required by the new revenue standard below. The following table disaggregates the Company’s revenue by source for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Successor Predecessor Year Ended December 31, Year Ended December 31, Period from October 2, 2016 through December 31, Period from January 1, 2016 through October 1, 2018 2017 2016 2016 Oil $ 214,651 $ 202,539 $ 57,093 $ 159,023 NGL 67,111 61,322 14,756 42,541 Natural gas 66,964 92,349 26,458 78,407 Other 669 1,089 149 13,838 Total revenues $ 349,395 $ 357,299 $ 98,456 $ 293,809 Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis. Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production tax expense in the consolidated statements of operations. Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2018, 2017 and 2016, the Company had revenues receivable of $31.8 million, $35.3 million and $42.6 million respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2018. Practical expedients and exemptions. The Company elected not to retrospectively restate contracts that were modified prior to January 1, 2017, and assumed that the contract terms in place at January 1, 2018 were in place from the inception of the contract. Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred. |
Proxy Contest
Proxy Contest | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Proxy Contest | Proxy Contest In the second quarter of 2018, the Company received notification from Carl C. Icahn and certain affiliated entities (together, "Icahn"), that they intended to nominate a full slate of candidates for election to the Board at the 2018 annual meeting that was held on June 19, 2018. The Company and Icahn, together with certain of their Board nominees, each entered into a settlement agreement which expanded the size of the Board to eight directors. Previous directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, Jr. were re-elected, and Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read were newly elected following the certification of the voting results, which occurred on June 22, 2018. As confirmed by general counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest would result in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 15. The Company incurred legal, consulting and advisory fees related to dealing with shareholders and the proxy contest of $7.1 million for the year ended December 31, 2018. |
Employee Termination Benefits
Employee Termination Benefits | 12 Months Ended |
Dec. 31, 2018 | |
Postemployment Benefits [Abstract] | |
Employee Termination Benefits | Employee Termination Benefits The following table presents a summary of employee termination benefits for t he years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Cash Share-Based Compensation (6) Number of Shares Total Employee Termination Benefits Year Ended December 31, 2018 (Successor) Executive Employee Termination Benefits(1) $ 11,945 $ 9,196 554 $ 21,141 Other Employee Termination Benefits(2) 7,581 3,935 209 11,516 $ 19,526 $ 13,131 763 $ 32,657 Year Ended December 31, 2017 (Successor) Executive Employee Termination Benefits(3) $ 2,500 $ 1,825 96 $ 4,325 Other Employee Termination Benefits 490 — — 490 $ 2,990 $ 1,825 96 $ 4,815 Period from October 2, 2016 through December 31, 2016 (Successor) Executive Employee Termination Benefits $ — $ 1,591 73 $ 1,591 Other Employee Termination Benefits(4) 8,048 2,695 118 10,743 $ 8,048 $ 4,286 191 $ 12,334 Period from January 1, 2016 to October 1, 2016 (Predecessor) Executive Employee Termination Benefits $ 810 $ 1,072 299 $ 1,882 Other Employee Termination Benefits(5) 12,427 4,047 941 16,474 $ 13,237 $ 5,119 1,240 $ 18,356 ____________________ 1. On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018. 2. As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. 3. Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert. 4. As a result of a reduction in workforce in the f ourth quarter of 2016, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. 5. As a result of a reduction in workforce in the f irst quarter of 2016 and discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operations in the first quarter of 2016, certain employees received termination benefits including cash severance and accelerated share-based compensation vesting upon separation of service from the Company. 6. Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit. See Note 15 for additional discussion of the Company’s share-based compensation awards. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company’s income tax (benefit) provision consisted of the following components (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Current Federal $ (33) $ (8,719) $ — $ — State (38) (30) 9 11 (71) (8,749) 9 11 Deferred Federal — — — — State — — — — — — — — Total (benefit) provision $ (71) $ (8,749) $ 9 $ 11 A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Computed at federal statutory rate $ (1,921) $ 13,409 $ (116,891) $ 504,283 State taxes, net of federal benefit 119 (284) (3,696) 10,512 Non-deductible expenses 849 1,711 144 462 Non-deductible debt costs — — — 22,694 Stock-based compensation 1,874 1,109 306 5,884 Discharge of debt and other reorganization related items 206 1,018 — 359,278 Return to provision adjustments (1) (1,292) 341,681 — — Impact of legislative changes — 243,801 — — Release of valuation allowance — (8,719) — — Change in valuation allowance 132 (602,452) 120,144 (903,102) Other (38) (23) 2 — Total (benefit) provision $ (71) $ (8,749) $ 9 $ 11 ____________________ 1. The adjustment for the period ended December 31, 2017, primarily related to the Company’s decision to file its 2016 income tax returns using an alternate method than previously estimated with respect to its Chapter 11 related transactions. Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. During the year ended December 31, 2017, the Company reduced the valuation allowance associated with deferred tax assets related to alternative minimum tax ("AMT") credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. As a result of the significant weight placed on the Company’s cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its remaining net deferred tax asset at December 31, 2017 and December 31, 2018. Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands): December 31, 2018 December 31, 2017 Deferred tax liabilities Investments(1) $ 112,343 $ 171,517 Derivative contracts 1,128 — Total deferred tax liabilities 113,471 171,517 Deferred tax assets Property, plant and equipment 267,865 391,273 Derivative contracts — 3,131 Net operating loss carryforwards 302,190 217,259 Tax credits and other carryforwards 35,640 33,001 Asset retirement obligations 15,016 18,843 Other 3,816 8,959 Total deferred tax assets 624,527 672,466 Valuation allowance (511,056) (500,949) Net deferred tax liability $ — $ — ____________________ 1. Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. The "Tax Cuts and Jobs Act" (the "TCJA") enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses ("NOLs"), and limitations on the deduction of interest expense and executive compensation. Based on our analysis of the TCJA and guidance currently available we recorded income tax expense of approximately $243.8 million in the period ended December 31, 2017, which was completely offset by a decrease in the corresponding valuation allowance. The provisional amount primarily related to the remeasurement of our gross deferred tax assets and liabilities existing at December 31, 2017 at the appropriate tax rate expected to exist at the time of their reversal. We completed our analysis of the impact of the TCJA and recorded an immaterial adjustment to income tax expense in the year ended December 31, 2018, which was completely offset by an increase in the corresponding valuation allowance. Internal Revenue Code ("IRC") Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016 that subjected certain of the Company's tax attributes, including $1.9 billion of federal NOL carryforwards to the IRC Section 382 limitation. This limitation is expected to result in $1.6 billion of the $1.9 billion of federal NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance were reduced in the period ended December 31, 2017. The limitation did not result in a tax liability for the tax years ended December 31, 2016, December 31, 2017, or December 31, 2018. Since the October 4, 2016 ownership change, the Company has generated additional NOLs that are not currently subject to an IRC Section 382 limitation. See "Note 19 - Income Taxes" in the 2017 Form 10-K for additional discussion with respect to the impact of income tax elections associated with the Chapter 11 reorganization. As of December 31, 2018, the Company had approximately $1.1 billion of federal NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.1 billion of federal NOL carryforwards, $0.8 billion expire during the years 2025 through 2037, while $0.3 billion do not have an expiration date. Additionally, the Company had federal tax credits in excess of $32.0 million which begin expiring in 2029. A reconciliation of the beginning and ending amount of the Company's unrecognized tax benefits is as follows (in thousands): Year Ended December 31, 2018 Year Ended December 31, 2017 Unrecognized tax benefit at January 1 $ 48 $ 84 Changes to unrecognized tax benefits related to a prior period — 2 Lapse of statute of limitations (48) (38) Unrecognized tax benefit at December 31 $ — $ 48 Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2017 and 2016, with none accrued in the year ended December 31, 2018. three five |
(Loss) Earnings per Share
(Loss) Earnings per Share | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
(Loss) Earnings per Share | (Loss) Earnings per Share As discussed in Note 1, on the Emergence Date, the Predecessor Company’s then-authorized common stock was canceled and the new Common Stock and Warrants were issued. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share: Net (Loss) Income Weighted Average Shares (Loss) Earnings Per Share (In thousands, except per share amounts) Year Ended December 31, 2018 (Successor) Basic loss per share $ (9,075) 35,057 $ (0.26) Effect of dilutive securities Restricted stock awards (1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (9,075) 35,057 $ (0.26) Year Ended December 31, 2017 (Successor) Basic earnings per share $ 47,062 32,442 $ 1.45 Effect of dilutive securities Restricted stock awards — 221 Performance share units(2) — — Warrants(2) — — Diluted earnings per share $ 47,062 32,663 $ 1.44 Period from October 2, 2016 to December 31, 2016 (Successor) Basic loss per share $ (333,982) 18,967 $ (17.61) Effect of dilutive securities Restricted stock awards(3) — — Warrants(3) — — Convertible Notes (4) — — Diluted loss per share $ (333,982) 18,967 $ (17.61) Period from January 1, 2016 to October 1, 2016 (Predecessor) Basic earnings per share $ 1,424,476 708,928 $ 2.01 Effect of dilutive securities Restricted stock and units(5) — — Diluted earnings per share $ 1,424,476 708,928 $ 2.01 ____________________ 1. No incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2018, as their effect was antidilutive under the treasury stock method. 2. No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method. 3. No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive under the treasury stock method. 4. Potential common shares related to the Convertible Notes covering 14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method. 5. No incremental shares of potentially dilutive restricted stock awards were included for the Predecessor 2016 Period as their effect was antidilutive under the treasury stock method. See Note 15 for discussion of the Company’s share-based compensation awards. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) | Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves. Capitalized Costs Related to Oil and Natural Gas Producing Activities The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands): December 31, 2018 2017 2016 Oil and natural gas properties Proved $ 1,269,091 $ 1,056,806 $ 840,201 Unproved 60,152 100,884 74,937 Total oil and natural gas properties 1,329,243 1,157,690 915,138 Less accumulated depreciation, depletion and impairment (580,132) (460,431) (353,030) Net oil and natural gas properties capitalized costs $ 749,111 $ 697,259 $ 562,108 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Acquisitions of properties Proved $ 30,641 $ 7,092 $ 5,142 $ 3,897 Unproved 4,197 91,139 5,491 1,899 Exploration 1,940 8,850 — 1,234 Development 158,361 187,264 27,429 149,924 Total cost incurred $ 195,139 $ 294,345 $ 38,062 $ 156,954 Results of Operations for Oil and Natural Gas Producing Activities The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings. Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Revenues $ 348,726 $ 356,210 $ 98,307 $ 279,971 Expenses Production costs 112,173 116,372 27,640 135,715 Depreciation and depletion 127,281 118,035 36,061 90,978 Impairment — — 319,087 657,392 Total expenses 239,454 234,407 382,788 884,085 Income (loss) before income taxes 109,272 121,803 (284,481) (604,114) Income tax expense (benefit) (1) 28,520 47,722 (112,427) (229,986) Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) $ 80,752 $ 74,081 $ (172,054) $ (374,128) ____________________ 1. Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits. Oil, Natural Gas and NGL Reserve Quantities Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of mandated economic assumptions; and • the judgment of the personnel preparing the estimates. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion. The following table represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Over 90% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2018, 2017 and 2016. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates. The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change. 2018 Activity. Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin. 2017 Activity. During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance. 2016 Activity. During 2016, on a pro forma combined basis, the Predecessor Company and Successor Company recognized total downward revisions of prior estimates of approximately 105.4 MMBoe, predominantly from revisions of approximately 94.7 MMBoe due to well performance and 12.1 MMBoe due to a decrease in commodity prices. The negative revisions from well performance were from the Mid-Continent area and resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years. Of the total performance revisions, approximately 85% were to gas and associated NGL reserves, with the revisions to gas mostly from changes made to late-life decline rates, and 15% were to oil reserves. Other decreases of reserves excluding production included the sale of WTO reserves of 24.6 MMBoe and 19.1 MMBoe of adjustment from change in accounting for Trusts. These decreases were partially offset by approximately 7.8 MMBoe of extensions due to successful drilling. The summary below presents changes in the Company’s estimated reserves. Oil NGL Natural Gas Total (MBbls) (MBbls) (MMcf)(1) MBoe Proved developed and undeveloped reserves As of December 31, 2015(2) - Predecessor 77,911 61,075 1,113,840 324,626 Adoption of ASU 2015-02 (6,971) (3,695) (50,508) (19,084) Revisions of previous estimates (39,973) (21,475) (415,568) (130,709) Extensions and discoveries 987 472 7,955 2,785 Sales of reserves in place (387) — (145,267) (24,598) Production (4,315) (3,358) (44,124) (15,027) As of October 1, 2016 - Predecessor 27,252 33,019 466,328 137,992 Revisions of previous estimates 23,978 1,139 915 25,270 Extensions and discoveries 2,868 448 10,309 5,034 Production (1,214) (999) (12,770) (4,341) As of December 31, 2016 - Successor 52,884 33,607 464,782 163,955 Revisions of previous estimates 804 2,628 44,679 10,879 Acquisitions of new reserves 18 70 683 202 Extensions and discoveries 12,446 1,914 30,080 19,373 Sales of reserves in place (204) (529) (7,055) (1,909) Production (4,157) (3,376) (44,237) (14,906) As of December 31, 2017 - Successor 61,791 34,314 488,932 177,594 Revisions of previous estimates (2,316) (8,952) (131,518) (33,188) Acquisitions of new reserves 2,146 4,131 54,436 15,350 Extensions and discoveries 11,148 2,320 35,185 19,332 Sales of reserves in place (5,273) (809) (2,969) (6,577) Production (3,477) (2,829) (36,175) (12,335) As of December 31, 2018 - Successor 64,019 28,175 407,891 160,176 Proved developed reserves As of December 31, 2015 - Predecessor 48,639 51,089 964,617 260,498 As of October 1, 2016 - Predecessor 24,541 30,238 428,050 126,121 As of December 31, 2016 - Successor 25,911 29,290 393,028 120,706 As of December 31, 2017 - Successor 25,845 29,922 407,988 123,765 As of December 31, 2018 - Successor 18,693 22,302 307,845 92,303 Proved undeveloped reserves As of December 31, 2015 - Predecessor 29,272 9,986 149,223 64,129 As of October 1, 2016 - Predecessor 2,711 2,781 38,278 11,872 As of December 31, 2016 - Successor 26,973 4,317 71,754 43,249 As of December 31, 2017 - Successor 35,946 4,392 80,944 53,829 As of December 31, 2018 - Successor 45,326 5,873 100,046 67,873 ____________________ 1. Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 2. Includes proved reserves attributable to noncontrolling interests as shown in the table below: Predecessor December 31, 2015 Oil (MBbl) 7,004 NGL (MBbl) 3,694 Natural gas (MMcf) 50,508 Standardized Measure of Discounted Future Net Cash Flows (Unaudited) The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows: • the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions; • pricing is applied based upon SEC prices at December 31, 2018, 2017, and 2016 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: At December 31, 2018 2017 2016 Oil (per barrel) $ 60.86 $ 48.47 $ 38.59 NGL (per barrel) $ 25.62 $ 20.28 $ 10.99 Natural gas (per Mcf) $ 1.77 $ 1.90 $ 1.56 • future development and production costs are determined based upon actual cost at year-end; • the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and • a discount factor of 10% per year is applied annually to the future net cash flows. The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands). December 31, 2018 2017 2016 Future cash inflows from production $ 5,339,265 $ 4,621,615 $ 3,136,762 Future production costs (1,996,689) (1,837,852) (1,454,798) Future development costs(1) (1,170,113) (966,203) (665,516) Future income tax expenses (2) — (107) (142) Undiscounted future net cash flows 2,172,463 1,817,453 1,016,306 10% annual discount (1,126,860) (1,068,159) (577,942) Standardized measure of discounted future net cash flows $ 1,045,603 $ 749,294 $ 438,364 ____________________ 1. Includes abandonment costs. 2. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws , including expected tax benefits to be realized from the utilization of net operating loss carryforwards. The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning present value $ 749,294 $ 438,364 $ 392,604 $ 1,314,562 Changes during the year Adoption of ASU 2015-02 — — — (224,965) Revenues less production (236,553) (239,838) (70,668) (144,256) Net changes in prices, production and other costs 316,095 347,458 35,684 (394,173) Development costs incurred 80,050 35,517 7,941 69,080 Net changes in future development costs (11,483) (64,484) (291,232) 436,041 Extensions and discoveries 102,961 112,556 14,986 12,449 Revisions of previous quantity estimates (91,038) 26,697 308,374 (728,254) Accretion of discount 70,576 37,226 9,375 91,337 Net change in income taxes 56 23 — 402 Purchases of reserves in-place 35,713 454 — — Sales of reserves in-place (2,029) (2,977) — (13,314) Timing differences and other(1) 31,961 58,298 31,300 (26,305) Net change for the year 296,309 310,930 45,760 (921,958) Ending present value(2) $ 1,045,603 $ 749,294 $ 438,364 $ 392,604 ____________________ 1. The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. 2. Standardized Measure w as determined using SEC prices, and does not reflect actual prices received or current market prices. |
Quarterly Financial Results (Un
Quarterly Financial Results (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Results (Unaudited) | Quarterly Financial Results (Unaudited) The Company’s operating results for each quarter of 2018 and 2017 are summarized below (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenues $ 87,128 $ 79,462 $ 97,660 $ 85,145 (Loss) income from operations(1)(2) $ (41,967) $ (33,685) $ 12,430 $ 52,847 Net (loss) income(1)(2) $ (40,894) $ (34,074) $ 11,715 $ 54,178 (Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders Basic $ (1.18) $ (0.97) $ 0.33 $ 1.53 Diluted $ (1.18) $ (0.97) $ 0.33 $ 1.53 ____________________ 1. Includes loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively. 2. Includes employee termination benefits of $31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter. First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Total revenues $ 98,350 $ 84,851 $ 80,892 $ 93,206 Income (loss) from operations(1)(2) $ 50,780 $ 23,348 $ (16,267) $ (18,230) Net income (loss)(1)(2) $ 50,808 $ 23,499 $ (8,485) $ (18,760) Income available (loss applicable) per share to SandRidge Energy, Inc. common stockholders Basic $ 1.90 $ 0.69 $ (0.25) $ (0.54) Diluted $ 1.90 $ 0.69 $ (0.25) $ (0.54) ____________________ 1. Includes (gain) loss on derivative contracts of $(34.2) million, $(23.5) million, $11.7 million and $21.9 million for the first, second, third and fourth quarters, respectively. 2. Includes employee termination benefits of $4.4 million for the second quarter and terminated merger costs of $8.2 million for the fourth quarter. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Nature of Business | Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States. |
Principles of Consolidation | Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company proportionately consolidates the activities of the Royalty Trusts. |
Reclassifications | Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. |
Use of Estimates | Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly. |
Cash and Cash Equivalents | Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. |
Restricted Cash | Restricted Cash. The Company |
Accounts Receivable, Net | Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are |
Fair Value of Financial Instruments | Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements. |
Fair Value of Non-financial Assets and Liabilities | Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary. |
Derivative Financial Instruments | Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 11 for further discussion of the Company’s derivatives. |
Oil and Natural Gas Operations | Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Successor Company capitalized gross internal costs of $8.8 million, $14.8 million and $4.0 million during the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $22.7 million to the full cost pool during the Predecessor 2016 Period. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center. |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 8 for further discussion of impairments. |
Capitalized Interest | Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. |
Debt Issuance Costs | Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt. |
Investments | Investments. Investments in marketable equity securities at December 31, 2017 related to the Company’s then-outstanding non-qualified deferred compensation plan. The investments in this plan were designated as available for sale and measured at fair value using quoted prices readily available in the market (fair value option) which requires unrealized gains and losses be reported in earnings. Investments are included in other current assets and other assets in the accompanying consolidated balance sheet at December 31, 2017. |
Asset Retirement Obligations | Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or |
Revenue Recognition | Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company made an accounting policy election on the Emergence Date to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $27.7 million, $29.1 million and $7.4 million of transportation costs as a reduction from revenues in the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, versus presenting $26.2 million of these costs as production expenses in the Predecessor 2016 Period. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See Note 17 for further information on the Company's accounting policies related to revenues. The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions of $1.7 million and $1.6 million at December 31, 2018 and 2017, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets. |
Allocation of Share-Based Compensation | Allocation of Share-Based Compensation. For both the Successor and Predecessor Companies, equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations. |
Income Taxes | Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense. |
Earnings per Share | Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards and warrants, using the treasury method, and convertible senior notes, using the if-converted method. Potentially dilutive securities for the Predecessor Company consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. During the Successor 2016 Period, the Company assumed the conversion of the Convertible Notes to common stock under the if-converted method and determined if it was more dilutive than including the expense associated with the Convertible Notes in the computation of income available to common stockholders during the period the Convertible Notes were outstanding. The Predecessor Company also assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock under the if-converted method and determined if it was more dilutive than including the preferred stock dividends or expense associated with the Convertible Senior Unsecured Notes, respectively, in the computation |
Commitments and Contingencies | Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 13 for discussion of the Company’s commitments and contingencies. |
Concentration of Risk | Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected. Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces. The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2018 - Successor Targa Midstream Services L.P. $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 - Successor Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % Period from October 2, 2016 through December 31, 2016 - Successor Targa Pipeline Mid-Continent West OK LLC $ 35,845 36.4 % Plains Marketing, L.P. $ 32,022 32.5 % Period from January 1, 2016 through October 1, 2016 - Predecessor Plains Marketing, L.P. $ 110,370 37.6 % Targa Pipeline Mid-Continent West OK LLC $ 108,238 36.8 % |
Recent Accounting Pronouncements | Recent Accounting Pronouncements. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenues from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 to January 1, 2018, for the Company. The ASU required adoption using either the retrospective transition method, which required restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company adopted Topic 606 and all the related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 17 for further discussion of the adoption of the new revenue standard. The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory,” which removed the prohibition in ASC 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption. The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption. The FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the disclosure Requirements for Fair Value Measurement," which removes, modifies or adds disclosure requirements regarding fair value measurements. The amendments in this ASU are effective for all entities beginning after December 15, 2019, with amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty requiring prospective adoption and all other amendments requiring retrospective adoption. Early adoption is permitted and the Company elected to adopt this ASU during the third quarter of 2018, which resulted in a change to the Company's fair value measurement disclosures on a prospective basis, but had no impact on its consolidated financial statements. Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” and other associated ASU's related to Topic 842 which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. This topic is effective for the Company on January 1, 2019. Early adoption is permitted. Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ and therefore will not have to reassess its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company will also utilize the short-term lease recognition exemption, which means assets and liabilities will not be recognized for the rights and obligations of qualifying leases, including existing short-term leases of those assets in transition. The Company does not plan to elect the use-of-hindsight. Upon adoption, the Company anticipates (i) recognizing assets and liabilities for the rights and obligations of its vehicle and equipment leases and, (ii) providing new disclosures about the Company’s leasing activities. The Company has completed the implementation of a lease contract management system and is finalizing processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases on and after the date of adoption. The Company will adopt Topic 842 using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company is still finalizing its evaluation of the January 1, 2019 adoption. The impact to recognize the assets and liabilities for the rights and obligations of the Company's leases on the balance sheet is not expected to be material at adoption. New disclosures will be required in the first quarter of 2019 to present information related to the Company's leases, including the Company's short-term leases, which are not required to be presented on the balance sheet utilizing the short-term lease recognition exemption. |
Successor | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |
Revenue Recognition | Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis. Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production tax expense in the consolidated statements of operations. Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2018, 2017 and 2016, the Company had revenues receivable of $31.8 million, $35.3 million and $42.6 million respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2018. Practical expedients and exemptions. The Company elected not to retrospectively restate contracts that were modified prior to January 1, 2017, and assumed that the contract terms in place at January 1, 2018 were in place from the inception of the contract. Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies Summary (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Reconciliation Of Enterprise Value To Estimated Reorganization Value | The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date (in thousands): Enterprise value $ 1,089,808 Plus: cash and cash equivalents 563,372 Plus: other working capital liabilities 131,766 Plus: other long-term liabilities 8,549 Reorganization value of Successor assets $ 1,793,495 |
Reorganization Items | The following table summarizes reorganization items for the Predecessor 2016 Period (in thousands): Unamortized long-term debt $ 3,546,847 Litigation claims (20,478) Rejections and cures of executory contracts (16,038) Ad valorem and franchise taxes (3,494) Legal and professional fees and expenses (44,920) Write off of director and officer insurance policy (7,533) Gain on accounts payable settlements 84,228 Loss on mortgage (8,153) Gain on preferred stock dividends 37,893 Fresh start valuation adjustments (28,549) Fair value of equity issued (827,424) Principal value of Convertible Notes issued (281,780) Gain on reorganization items, net $ 2,430,599 |
Schedules of Concentration of Risk | The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2018 - Successor Targa Midstream Services L.P. $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 - Successor Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % Period from October 2, 2016 through December 31, 2016 - Successor Targa Pipeline Mid-Continent West OK LLC $ 35,845 36.4 % Plains Marketing, L.P. $ 32,022 32.5 % Period from January 1, 2016 through October 1, 2016 - Predecessor Plains Marketing, L.P. $ 110,370 37.6 % Targa Pipeline Mid-Continent West OK LLC $ 108,238 36.8 % |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Supplemental Disclosure of Cash Flow Information Cash paid for reorganization items $ — $ — $ — $ (55,606) Cash paid for interest, net of amounts capitalized $ (4,045) $ (2,438) $ (1,183) $ (104,609) Cash received (paid) for income taxes $ 4,381 $ 4,348 $ — $ (28) Supplemental Disclosure of Noncash Investing and Financing Activities Cumulative effect of adoption of ASU 2015-02 $ — $ — $ — $ (247,566) Property, plant and equipment transferred in settlement of contract $ — $ — $ — $ 215,635 Change in accrued capital expenditures $ (15,861) $ (28,999) $ 10,630 $ 25,045 Equity issued for debt $ — $ (268,779) $ (13,001) $ (4,409) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on Recurring Basis | The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands): December 31, 2018 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,286 $ — $ — $ 5,286 $ — $ 5,286 $ — $ — $ 5,286 December 31, 2017 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,582 $ — (4,272) $ 1,310 Investments 5,072 — — — 5,072 $ 5,072 $ 5,582 $ — $ (4,272) $ 6,382 Liabilities Commodity derivative contracts $ — $ 18,467 $ — $ (4,272) $ 14,195 $ — $ 18,467 $ — $ (4,272) $ 14,195 ____________________ 1. Represents the impact of netting assets and liabilities with counterparties where the right of offset exists. |
Estimated Fair Value and Carrying Value of the Company's Notes | The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands): December 31, 2018 December 31, 2017 Fair Value Carrying Value Fair Value Carrying Value Building Note $ — $ — $ 42,526 $ 37,502 |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Summary of Accounts Receivable | A summary of accounts receivable is as follows (in thousands): December 31, 2018 2017 Oil, natural gas and NGL sales $ 31,780 $ 35,301 Joint interest billing 13,083 29,505 Oil and natural gas services 604 639 Other 1,331 7,106 Total accounts receivable 46,798 72,551 Less: allowance for doubtful accounts (1,295) (1,274) Total accounts receivable, net $ 45,503 $ 71,277 |
Balance and Activity in Allowance for Doubtful Accounts | The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning balance $ 1,274 $ 880 $ — $ 4,847 Additions charged to costs and expenses(1) 758 397 880 16,695 Deductions(2) (737) (3) — (751) Impact of fresh start accounting — — — (20,791) Ending balance $ 1,295 $ 1,274 $ 880 $ — ____________________ 1. The Predecessor 2016 Period includes a $16.7 million addition for a joint interest account receivable after determining that future collection was doubtful when the joint interest owner filed for bankruptcy. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment consists of the following (in thousands): December 31, 2018 2017 Oil and natural gas properties Proved $ 1,269,091 $ 1,056,806 Unproved 60,152 100,884 Total oil and natural gas properties 1,329,243 1,157,690 Less accumulated depreciation, depletion and impairment (580,132) (460,431) Net oil and natural gas properties capitalized costs 749,111 697,259 Land 4,400 4,500 Electrical infrastructure 131,176 131,010 Non-oil and natural gas equipment 13,458 26,809 Buildings and structures 77,148 79,548 Total 226,182 241,867 Less accumulated depreciation and amortization (25,344) (15,886) Other property, plant and equipment, net 200,838 225,981 Total property, plant and equipment, net $ 949,949 $ 923,240 |
Capitalized Costs of Unproved Properties Excluded from Amortization | The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2018 (in thousands): Year Cost Incurred Total 2018 2017 2016 2015 and Prior Property acquisition $ 59,522 $ 3,859 $ 20,647 $ 13,735 $ 21,281 Exploration 630 13 323 243 51 Total costs incurred $ 60,152 $ 3,872 $ 20,970 $ 13,978 $ 21,332 |
Impairment (Tables)
Impairment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Impairment by Asset Class | Impairment The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. Estimated fair values of drilling, midstream, electrical transmission and other assets were determined in accordance with the policies discussed in Note 2. Impairment for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Full cost pool ceiling limitation(1)(2) $ — $ — $ 319,087 $ 657,392 Drilling assets(3)(4) 22 4,019 — 3,511 Electrical infrastructure assets(5) — — — 55,600 Midstream assets(6) 4,148 — — 1,691 $ 4,170 $ 4,019 $ 319,087 $ 718,194 ____________________ 1. Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting , whereby the fair value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment. 2. Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairment recorded in the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes. 3. Impairment recorded in the year s ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. 4. Impairment recorded in the Predecessor 2016 Period resulted from the write-down of certain drilling assets after the Company discontinued drilling operations in the Permian region. 5. Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage. 6. Im pairment recorded in 2018 reflects the write down of midstream generator assets classified as held for sale to the net realizable value. The impairment recorded in the Predecessor 2016 Period resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO 2 compressor station after determining that their future use was limited. |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Expenses (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses consist of the following (in thousands): December 31, 2018 2017 Accounts payable and other accrued expenses $ 78,219 $ 90,423 Payroll and benefits 12,891 21,475 Production payable 12,767 18,059 Taxes payable 5,350 3,983 Drilling advances 2,031 3,830 Accrued interest 539 1,385 Total accounts payable and accrued expenses $ 111,797 $ 139,155 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-term debt consists of the following (in thousands): December 31, 2018 2017 Credit facility $ — $ — Building Note — 37,502 Total debt — 37,502 Less: current maturities of long-term debt — — Long-term debt $ — $ 37,502 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Offsetting Assets and Liabilities | The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2018 and 2017 (in thousands): December 31, 2018 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,286 $ — $ 5,286 $ — $ 5,286 Total $ 5,286 $ — $ 5,286 $ — $ 5,286 December 31, 2017 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,582 $ (4,272) $ 1,310 $ — $ 1,310 Total $ 5,582 $ (4,272) $ 1,310 $ — $ 1,310 Liabilities Derivative contracts - current $ 14,899 $ (4,272) $ 10,627 $ (10,627) $ — Derivative contracts - noncurrent 3,568 — 3,568 (3,568) — Total $ 18,467 $ (4,272) $ 14,195 $ (14,195) $ — |
Open Oil and Natural Gas Commodity Derivative Contracts | At December 31, 2018, the Company’s open commodity derivative contracts consisted of the following: Natural Gas Price Swaps Notional (MMcf) Weighted Average Fixed Price January 2019 - March 2019 4,500 $ 4.28 |
Fair Value of Derivative Contracts | The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands): December 31, December 31, Type of Contract Balance Sheet Classification 2018 2017 Derivative assets Natural gas price swaps Derivative contracts - current $ 5,286 $ 5,582 Derivative liabilities Oil price swaps Derivative contracts - current — (14,899) Oil price swaps Derivative contracts - noncurrent — (3,568) Total net derivative contracts $ 5,286 $ (12,885) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations | The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning balance $ 77,544 $ 106,481 $ 92,413 $ 103,578 Liability incurred upon acquiring and drilling wells 7,079 1,336 121 505 Revisions in estimated cash flows(1) 870 (28,565) 12,397 — Liability settled or disposed in current period(2) (31,967) (11,308) (540) (36,979) Accretion 6,538 9,600 2,090 4,365 Impact of fresh start accounting — — — 20,944 Ending balance 60,064 77,544 106,481 92,413 Less: current portion 25,393 41,017 66,154 65,678 Asset retirement obligations, net of current $ 34,671 $ 36,527 $ 40,327 $ 26,735 ____________________ 1. Revisions for the year s ended December 31, 2018 and 2017, and the Successor 2016 Period relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates. 2. Liability settled or disposed for the year ended December 31, 2018 includes $26.9 million associated with the Permian Properties sold in November 2018. Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Successor | |
Equity, Class of Treasury Stock [Line Items] | |
Treasury Stock Activity | The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired. Successor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Number of shares withheld for taxes 495 349 5 Value of shares withheld for taxes $ 7,420 $ 6,730 $ 110 |
Predecessor | |
Equity, Class of Treasury Stock [Line Items] | |
Preferred Stock Dividends | Preferred stock dividend accruals in arrears prior to the Emergence Date for the Predecessor Company’s 8.5% and 7.0% convertible perpetual preferred stock were as follows (in thousands): Predecessor Period from January 1, 2016 through October 1, 2016 8.5% Convertible perpetual preferred stock Dividends in arrears $ 11,262 7.0% Convertible perpetual preferred stock Dividends in arrears $ 21,000 |
Share Based Compensation (Table
Share Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | The following tables summarize the Successor Company's share and incentive-based compensation for the years ended December 31, 2018 and 2017, and the Successor 2016 Period (in thousands): Recurring Compensation Expense(1) Executive Terminations(2) Reduction in Force(2) Accelerated Vesting(3) Total Year Ended December 31, 2018 Equity-classified awards: Restricted stock awards $ 4,735 $ 8,140 $ 3,777 $ 5,181 $ 21,833 Performance share units 619 1,056 158 610 2,443 Total share-based compensation expense 5,354 9,196 3,935 5,791 24,276 Liability-classified awards: Performance units 756 2,151 558 1,309 4,774 Total share and incentive-based compensation expense 6,110 11,347 4,493 7,100 29,050 Less: Capitalized compensation expense (482) — — (555) (1,037) Share and incentive-based compensation expense, net $ 5,628 $ 11,347 $ 4,493 $ 6,545 $ 28,013 Year Ended December 31, 2017 Equity-classified awards: Restricted stock awards $ 14,731 $ 1,825 $ — $ — $ 16,556 Performance share units 1,356 — — — 1,356 Total share-based compensation expense 16,087 1,825 — — 17,912 Liability-classified awards: Performance units 2,574 — — — 2,574 Total share and incentive-based compensation expense 18,661 1,825 — — 20,486 Less: Capitalized compensation expense (2,521) — — — (2,521) Share and incentive-based compensation expense, net $ 16,140 $ 1,825 $ — $ — $ 17,965 Period from October 2, 2016 through December 31, 2016 Equity-classified awards: Restricted stock awards $ 2,296 $ — $ 4,285 $ — $ 6,581 Total share-based compensation expense 2,296 — 4,285 — 6,581 Liability-classified awards: Performance units 528 — 737 — 1,265 Total share and incentive-based compensation expense 2,824 — 5,022 — 7,846 Less: Capitalized compensation expense (407) — — — (407) Share and incentive-based compensation expense, net $ 2,417 $ — $ 5,022 $ — $ 7,439 ____________________ 1. Recorded in general and administrative expense in the accompanying consolidated statements of operations. 2. Recorded in employee termination benefits in the accompanying consolidated statements of operations. 3. Recorded in accelerated vesting of employment compensation in the accompanying consolidated statements of operations. |
Performance Shares | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |
Summary of Unvested Restricted Stock Awards | The following table presents a summary of the Company's performance share units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance share units outstanding at December 31, 2016 — Granted 199 Vested — Forfeited / Canceled (16) Unvested performance share units outstanding at December 31, 2017 183 Granted 111 Vested (177) Forfeited / Canceled (6) Unvested performance share units outstanding at December 31, 2018 111 $ 20.41 |
Performance Units | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |
Incentive-Based Compensation, Performance-based Units, Activity During Period | The following table presents a summary of the Company's performance units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance units outstanding at October 1, 2016 — Granted 97 Vested (1) Forfeited / Canceled (9) Unvested performance units outstanding at December 31, 2016 87 Granted — Vested (32) Forfeited / Canceled (6) Unvested performance units outstanding at December 31, 2017 49 Granted — Vested (48) Forfeited / Canceled (1) Unvested performance units outstanding at December 31, 2018 — — |
Successor | Restricted Stock | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |
Summary of Unvested Restricted Stock Awards | The following table presents a summary of the Successor Company’s unvested restricted stock awards: Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at October 1, 2016 — $ — Granted 1,448 $ 24.32 Vested (14) $ 24.32 Forfeited / Canceled (27) $ 24.32 Unvested restricted shares outstanding at December 31, 2016 1,407 $ 24.32 Granted 671 $ 19.97 Vested (827) $ 23.23 Forfeited / Canceled (146) $ 23.52 Unvested restricted shares outstanding at December 31, 2017 1,105 $ 22.62 Granted 370 $ 16.00 Vested (1,066) $ 22.63 Forfeited / Canceled (44) $ 21.04 Unvested restricted shares outstanding at December 31, 2018 365 $ 16.07 |
Predecessor | Restricted Stock | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |
Summary of Unvested Restricted Stock Awards | The following table presents a summary of the Predecessor Company’s unvested restricted stock awards. Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at December 31, 2015 5,626 $ 4.85 Granted — $ — Vested (3,034) $ 5.34 Forfeited / Canceled (2,592) $ 4.31 Predecessor ending unvested restricted shares at October 1, 2016 — $ — |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates the Company’s revenue by source for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Successor Predecessor Year Ended December 31, Year Ended December 31, Period from October 2, 2016 through December 31, Period from January 1, 2016 through October 1, 2018 2017 2016 2016 Oil $ 214,651 $ 202,539 $ 57,093 $ 159,023 NGL 67,111 61,322 14,756 42,541 Natural gas 66,964 92,349 26,458 78,407 Other 669 1,089 149 13,838 Total revenues $ 349,395 $ 357,299 $ 98,456 $ 293,809 |
Employee Termination Benefits (
Employee Termination Benefits (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Postemployment Benefits [Abstract] | |
Schedule of Postemployment Benefits | The following table presents a summary of employee termination benefits for t he years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands): Cash Share-Based Compensation (6) Number of Shares Total Employee Termination Benefits Year Ended December 31, 2018 (Successor) Executive Employee Termination Benefits(1) $ 11,945 $ 9,196 554 $ 21,141 Other Employee Termination Benefits(2) 7,581 3,935 209 11,516 $ 19,526 $ 13,131 763 $ 32,657 Year Ended December 31, 2017 (Successor) Executive Employee Termination Benefits(3) $ 2,500 $ 1,825 96 $ 4,325 Other Employee Termination Benefits 490 — — 490 $ 2,990 $ 1,825 96 $ 4,815 Period from October 2, 2016 through December 31, 2016 (Successor) Executive Employee Termination Benefits $ — $ 1,591 73 $ 1,591 Other Employee Termination Benefits(4) 8,048 2,695 118 10,743 $ 8,048 $ 4,286 191 $ 12,334 Period from January 1, 2016 to October 1, 2016 (Predecessor) Executive Employee Termination Benefits $ 810 $ 1,072 299 $ 1,882 Other Employee Termination Benefits(5) 12,427 4,047 941 16,474 $ 13,237 $ 5,119 1,240 $ 18,356 ____________________ 1. On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018. 2. As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. 3. Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert. 4. As a result of a reduction in workforce in the f ourth quarter of 2016, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. 5. As a result of a reduction in workforce in the f irst quarter of 2016 and discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operations in the first quarter of 2016, certain employees received termination benefits including cash severance and accelerated share-based compensation vesting upon separation of service from the Company. 6. Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
(Benefit) Provision for Income Taxes | The Company’s income tax (benefit) provision consisted of the following components (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Current Federal $ (33) $ (8,719) $ — $ — State (38) (30) 9 11 (71) (8,749) 9 11 Deferred Federal — — — — State — — — — — — — — Total (benefit) provision $ (71) $ (8,749) $ 9 $ 11 |
Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate | A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Computed at federal statutory rate $ (1,921) $ 13,409 $ (116,891) $ 504,283 State taxes, net of federal benefit 119 (284) (3,696) 10,512 Non-deductible expenses 849 1,711 144 462 Non-deductible debt costs — — — 22,694 Stock-based compensation 1,874 1,109 306 5,884 Discharge of debt and other reorganization related items 206 1,018 — 359,278 Return to provision adjustments (1) (1,292) 341,681 — — Impact of legislative changes — 243,801 — — Release of valuation allowance — (8,719) — — Change in valuation allowance 132 (602,452) 120,144 (903,102) Other (38) (23) 2 — Total (benefit) provision $ (71) $ (8,749) $ 9 $ 11 ____________________ 1. The adjustment |
Deferred Tax Assets and Liabilities | Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands): December 31, 2018 December 31, 2017 Deferred tax liabilities Investments(1) $ 112,343 $ 171,517 Derivative contracts 1,128 — Total deferred tax liabilities 113,471 171,517 Deferred tax assets Property, plant and equipment 267,865 391,273 Derivative contracts — 3,131 Net operating loss carryforwards 302,190 217,259 Tax credits and other carryforwards 35,640 33,001 Asset retirement obligations 15,016 18,843 Other 3,816 8,959 Total deferred tax assets 624,527 672,466 Valuation allowance (511,056) (500,949) Net deferred tax liability $ — $ — ____________________ |
Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of the Company's unrecognized tax benefits is as follows (in thousands): Year Ended December 31, 2018 Year Ended December 31, 2017 Unrecognized tax benefit at January 1 $ 48 $ 84 Changes to unrecognized tax benefits related to a prior period — 2 Lapse of statute of limitations (48) (38) Unrecognized tax benefit at December 31 $ — $ 48 |
(Loss) Earnings per Share (Tabl
(Loss) Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share | The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share: Net (Loss) Income Weighted Average Shares (Loss) Earnings Per Share (In thousands, except per share amounts) Year Ended December 31, 2018 (Successor) Basic loss per share $ (9,075) 35,057 $ (0.26) Effect of dilutive securities Restricted stock awards (1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (9,075) 35,057 $ (0.26) Year Ended December 31, 2017 (Successor) Basic earnings per share $ 47,062 32,442 $ 1.45 Effect of dilutive securities Restricted stock awards — 221 Performance share units(2) — — Warrants(2) — — Diluted earnings per share $ 47,062 32,663 $ 1.44 Period from October 2, 2016 to December 31, 2016 (Successor) Basic loss per share $ (333,982) 18,967 $ (17.61) Effect of dilutive securities Restricted stock awards(3) — — Warrants(3) — — Convertible Notes (4) — — Diluted loss per share $ (333,982) 18,967 $ (17.61) Period from January 1, 2016 to October 1, 2016 (Predecessor) Basic earnings per share $ 1,424,476 708,928 $ 2.01 Effect of dilutive securities Restricted stock and units(5) — — Diluted earnings per share $ 1,424,476 708,928 $ 2.01 ____________________ 1. No incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2018, as their effect was antidilutive under the treasury stock method. 2. No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method. 3. No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive under the treasury stock method. 4. Potential common shares related to the Convertible Notes covering 14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method. 5. No incremental shares of potentially dilutive restricted stock awards were included for the Predecessor 2016 Period as their effect was antidilutive under the treasury stock method. |
Supplemental Information on O_2
Supplemental Information on Oil and Natural Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities | The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands): December 31, 2018 2017 2016 Oil and natural gas properties Proved $ 1,269,091 $ 1,056,806 $ 840,201 Unproved 60,152 100,884 74,937 Total oil and natural gas properties 1,329,243 1,157,690 915,138 Less accumulated depreciation, depletion and impairment (580,132) (460,431) (353,030) Net oil and natural gas properties capitalized costs $ 749,111 $ 697,259 $ 562,108 |
Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development | Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Acquisitions of properties Proved $ 30,641 $ 7,092 $ 5,142 $ 3,897 Unproved 4,197 91,139 5,491 1,899 Exploration 1,940 8,850 — 1,234 Development 158,361 187,264 27,429 149,924 Total cost incurred $ 195,139 $ 294,345 $ 38,062 $ 156,954 |
Results of Operations for Oil, Natural Gas and NGL Producing Activities | The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings. Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Revenues $ 348,726 $ 356,210 $ 98,307 $ 279,971 Expenses Production costs 112,173 116,372 27,640 135,715 Depreciation and depletion 127,281 118,035 36,061 90,978 Impairment — — 319,087 657,392 Total expenses 239,454 234,407 382,788 884,085 Income (loss) before income taxes 109,272 121,803 (284,481) (604,114) Income tax expense (benefit) (1) 28,520 47,722 (112,427) (229,986) Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) $ 80,752 $ 74,081 $ (172,054) $ (374,128) ____________________ 1. Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits. |
Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves | The summary below presents changes in the Company’s estimated reserves. Oil NGL Natural Gas Total (MBbls) (MBbls) (MMcf)(1) MBoe Proved developed and undeveloped reserves As of December 31, 2015(2) - Predecessor 77,911 61,075 1,113,840 324,626 Adoption of ASU 2015-02 (6,971) (3,695) (50,508) (19,084) Revisions of previous estimates (39,973) (21,475) (415,568) (130,709) Extensions and discoveries 987 472 7,955 2,785 Sales of reserves in place (387) — (145,267) (24,598) Production (4,315) (3,358) (44,124) (15,027) As of October 1, 2016 - Predecessor 27,252 33,019 466,328 137,992 Revisions of previous estimates 23,978 1,139 915 25,270 Extensions and discoveries 2,868 448 10,309 5,034 Production (1,214) (999) (12,770) (4,341) As of December 31, 2016 - Successor 52,884 33,607 464,782 163,955 Revisions of previous estimates 804 2,628 44,679 10,879 Acquisitions of new reserves 18 70 683 202 Extensions and discoveries 12,446 1,914 30,080 19,373 Sales of reserves in place (204) (529) (7,055) (1,909) Production (4,157) (3,376) (44,237) (14,906) As of December 31, 2017 - Successor 61,791 34,314 488,932 177,594 Revisions of previous estimates (2,316) (8,952) (131,518) (33,188) Acquisitions of new reserves 2,146 4,131 54,436 15,350 Extensions and discoveries 11,148 2,320 35,185 19,332 Sales of reserves in place (5,273) (809) (2,969) (6,577) Production (3,477) (2,829) (36,175) (12,335) As of December 31, 2018 - Successor 64,019 28,175 407,891 160,176 Proved developed reserves As of December 31, 2015 - Predecessor 48,639 51,089 964,617 260,498 As of October 1, 2016 - Predecessor 24,541 30,238 428,050 126,121 As of December 31, 2016 - Successor 25,911 29,290 393,028 120,706 As of December 31, 2017 - Successor 25,845 29,922 407,988 123,765 As of December 31, 2018 - Successor 18,693 22,302 307,845 92,303 Proved undeveloped reserves As of December 31, 2015 - Predecessor 29,272 9,986 149,223 64,129 As of October 1, 2016 - Predecessor 2,711 2,781 38,278 11,872 As of December 31, 2016 - Successor 26,973 4,317 71,754 43,249 As of December 31, 2017 - Successor 35,946 4,392 80,944 53,829 As of December 31, 2018 - Successor 45,326 5,873 100,046 67,873 ____________________ 1. Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 2. Includes proved reserves attributable to noncontrolling interests as shown in the table below: Predecessor December 31, 2015 Oil (MBbl) 7,004 NGL (MBbl) 3,694 Natural gas (MMcf) 50,508 |
Calculation of Weighted Average Per Unit Prices | The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: At December 31, 2018 2017 2016 Oil (per barrel) $ 60.86 $ 48.47 $ 38.59 NGL (per barrel) $ 25.62 $ 20.28 $ 10.99 Natural gas (per Mcf) $ 1.77 $ 1.90 $ 1.56 |
Standardized Measure of Discounted Future Cash Flows | The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands). December 31, 2018 2017 2016 Future cash inflows from production $ 5,339,265 $ 4,621,615 $ 3,136,762 Future production costs (1,996,689) (1,837,852) (1,454,798) Future development costs(1) (1,170,113) (966,203) (665,516) Future income tax expenses (2) — (107) (142) Undiscounted future net cash flows 2,172,463 1,817,453 1,016,306 10% annual discount (1,126,860) (1,068,159) (577,942) Standardized measure of discounted future net cash flows $ 1,045,603 $ 749,294 $ 438,364 ____________________ 1. Includes abandonment costs. 2. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws , including expected tax benefits to be realized from the utilization of net operating loss carryforwards. |
Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves | The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning present value $ 749,294 $ 438,364 $ 392,604 $ 1,314,562 Changes during the year Adoption of ASU 2015-02 — — — (224,965) Revenues less production (236,553) (239,838) (70,668) (144,256) Net changes in prices, production and other costs 316,095 347,458 35,684 (394,173) Development costs incurred 80,050 35,517 7,941 69,080 Net changes in future development costs (11,483) (64,484) (291,232) 436,041 Extensions and discoveries 102,961 112,556 14,986 12,449 Revisions of previous quantity estimates (91,038) 26,697 308,374 (728,254) Accretion of discount 70,576 37,226 9,375 91,337 Net change in income taxes 56 23 — 402 Purchases of reserves in-place 35,713 454 — — Sales of reserves in-place (2,029) (2,977) — (13,314) Timing differences and other(1) 31,961 58,298 31,300 (26,305) Net change for the year 296,309 310,930 45,760 (921,958) Ending present value(2) $ 1,045,603 $ 749,294 $ 438,364 $ 392,604 ____________________ 1. The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. 2. Standardized Measure w as determined using SEC prices, and does not reflect actual prices received or current market prices. |
Quarterly Financial Results (_2
Quarterly Financial Results (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Results (Unaudited) | The Company’s operating results for each quarter of 2018 and 2017 are summarized below (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenues $ 87,128 $ 79,462 $ 97,660 $ 85,145 (Loss) income from operations(1)(2) $ (41,967) $ (33,685) $ 12,430 $ 52,847 Net (loss) income(1)(2) $ (40,894) $ (34,074) $ 11,715 $ 54,178 (Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders Basic $ (1.18) $ (0.97) $ 0.33 $ 1.53 Diluted $ (1.18) $ (0.97) $ 0.33 $ 1.53 ____________________ 1. Includes loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively. 2. Includes employee termination benefits of $31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter. First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Total revenues $ 98,350 $ 84,851 $ 80,892 $ 93,206 Income (loss) from operations(1)(2) $ 50,780 $ 23,348 $ (16,267) $ (18,230) Net income (loss)(1)(2) $ 50,808 $ 23,499 $ (8,485) $ (18,760) Income available (loss applicable) per share to SandRidge Energy, Inc. common stockholders Basic $ 1.90 $ 0.69 $ (0.25) $ (0.54) Diluted $ 1.90 $ 0.69 $ (0.25) $ (0.54) ____________________ 1. Includes (gain) loss on derivative contracts of $(34.2) million, $(23.5) million, $11.7 million and $21.9 million for the first, second, third and fourth quarters, respectively. 2. Includes employee termination benefits of $4.4 million for the second quarter and terminated merger costs of $8.2 million for the fourth quarter. |
Voluntary Reorganization unde_2
Voluntary Reorganization under Chapter 11 Proceedings - Narrative (Details) - USD ($) shares in Millions | Feb. 10, 2017 | Oct. 04, 2016 | Oct. 01, 2016 | Feb. 28, 2017 | Feb. 09, 2017 | Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Oct. 31, 2018 |
Series A Warrants | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 4.6 | ||||||||
Series B Warrants | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 2 | ||||||||
Predecessor | 7.0% Convertible perpetual preferred stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Dividend rate, percentage | 7.00% | ||||||||
Predecessor | 8.5% Convertible perpetual preferred stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Dividend rate, percentage | 8.50% | ||||||||
Revolving Credit Facility | Amended New Credit Facility | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Line of credit facility, current borrowing capacity | $ 425,000,000 | $ 350,000,000 | |||||||
Convertible Debt | New Convertible Notes | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Face amount of debt instrument | $ 281,800,000 | $ 281,800,000 | |||||||
Common stock issued for debt (in shares) | 14.1 | 15 | 0.3 | 0.7 | |||||
Fair value of debt | $ 445,700,000 | 445,700,000 | |||||||
Convertible Debt | Successor | New Convertible Notes | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Common stock issued for debt (in shares) | 14.1 | ||||||||
Secured Notes | Building Note | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Face amount of debt instrument | 35,000,000 | 35,000,000 | |||||||
Fair value of debt | 36,600,000 | $ 36,600,000 | |||||||
Proceeds from issuance of debt | $ 26,800,000 | ||||||||
Plan of Reorganization | Predecessor | 7.0% Convertible perpetual preferred stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Dividend rate, percentage | 7.00% | ||||||||
Plan of Reorganization | Predecessor | 8.5% Convertible perpetual preferred stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Dividend rate, percentage | 8.50% | ||||||||
Plan of Reorganization | Successor | New Common Stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Common stock, shares authorized (in shares) | 18.9 | ||||||||
Plan of Reorganization | Successor | New First Lien Exit Facility | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Cash collateral | $ 50,000,000 | ||||||||
Plan of Reorganization | Successor | Holders of Senior Secured Notes | New Common Stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 13.7 | ||||||||
Plan of Reorganization | Successor | Holders of Unsecured Claims | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Cash payments for prepetition obligations | $ 36,700,000 | ||||||||
Plan of Reorganization | Successor | Holders of Unsecured Claims | Series A Warrants | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 4.5 | ||||||||
Number of shares to be issued (in shares) | 4.9 | ||||||||
Plan of Reorganization | Successor | Holders of Unsecured Claims | Series B Warrants | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 1.9 | ||||||||
Number of shares to be issued (in shares) | 2.1 | ||||||||
Plan of Reorganization | Successor | Holders of Unsecured Claims | New Common Stock | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Issuance of common stock (in shares) | 5.2 | ||||||||
Number of shares to be issued (in shares) | 5.7 | ||||||||
Plan of Reorganization | Revolving Credit Facility | Successor | New First Lien Exit Facility | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Line of credit facility, current borrowing capacity | $ 425,000,000 | ||||||||
Plan of Reorganization | Revolving Credit Facility | Successor | Holders of Senior Credit Facility | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Cash payments for prepetition obligations | 35,000,000 | ||||||||
Plan of Reorganization | Convertible Debt | Successor | Holders of Senior Secured Notes | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Face amount of debt instrument | 281,800,000 | ||||||||
Plan of Reorganization | Secured Notes | Successor | Building Note | |||||||||
Restructuring Cost and Reserve [Line Items] | |||||||||
Face amount of debt instrument | 35,000,000 | ||||||||
Fair value of debt | 36,600,000 | ||||||||
Proceeds from issuance of debt | $ 26,800,000 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Significant Accounting Policies [Line Items] | ||||
Enterprise value | $ 1,089,808,000 | |||
Capitalized costs | $ 38,062,000 | $ 195,139,000 | $ 294,345,000 | |
Maximum reserves sold from cost center not expected to result in significant alteration (less than) | 25.00% | |||
Natural gas balancing liability | $ 1,700,000 | 1,600,000 | ||
Successor | Oil, natural gas and NGL revenues | ||||
Significant Accounting Policies [Line Items] | ||||
Transportation costs | 7,400,000 | 27,700,000 | 29,100,000 | |
Successor | Internal Costs | ||||
Significant Accounting Policies [Line Items] | ||||
Capitalized costs | 4,000,000 | $ 8,800,000 | 14,800,000 | |
Successor | Oil And Gas Unproved Properties | ||||
Significant Accounting Policies [Line Items] | ||||
Interest capitalized during period | $ 0 | $ 0 | ||
Predecessor | ||||
Significant Accounting Policies [Line Items] | ||||
Capitalized costs | 156,954,000 | |||
Predecessor | Production expenses | ||||
Significant Accounting Policies [Line Items] | ||||
Transportation costs | 26,200,000 | |||
Predecessor | Internal Costs | ||||
Significant Accounting Policies [Line Items] | ||||
Capitalized costs | 22,700,000 | |||
Predecessor | Oil And Gas Unproved Properties | ||||
Significant Accounting Policies [Line Items] | ||||
Interest capitalized during period | 2,200,000 | |||
Minimum | Successor | Buildings and structures | ||||
Significant Accounting Policies [Line Items] | ||||
Property, plant and equipment, useful life | 7 years | |||
Minimum | Successor | Equipment | ||||
Significant Accounting Policies [Line Items] | ||||
Property, plant and equipment, useful life | 1 year | |||
Minimum | Predecessor | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated enterprise value | 1,000,000,000 | |||
Maximum | Successor | Buildings and structures | ||||
Significant Accounting Policies [Line Items] | ||||
Property, plant and equipment, useful life | 39 years | |||
Maximum | Successor | Equipment | ||||
Significant Accounting Policies [Line Items] | ||||
Property, plant and equipment, useful life | 27 years | |||
Maximum | Predecessor | ||||
Significant Accounting Policies [Line Items] | ||||
Estimated enterprise value | $ 1,300,000,000 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Reconciliation of Enterprise Value to Reorganization Value (Details) - Successor $ in Thousands | Oct. 01, 2016USD ($) |
Reconciliation Of Enterprise Value To Estimated Reorganization Value [Line Items] | |
Enterprise value | $ 1,089,808 |
Plus: cash and cash equivalents | 563,372 |
Plus: other working capital liabilities | 131,766 |
Plus: other long-term liabilities | 8,549 |
Reorganization value of Successor assets | $ 1,793,495 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Reorganization Items (Details) - Predecessor - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Oct. 01, 2016 | Dec. 31, 2016 | |
Schedule of Reorganization Items [Line Items] | ||
Unamortized long-term debt | $ 3,546,847 | |
Litigation claims | (20,478) | |
Rejections and cures of executory contracts | (16,038) | |
Ad valorem and franchise taxes | (3,494) | |
Legal and professional fees and expenses | (44,920) | |
Write off of director and officer insurance policy | (7,533) | |
Gain on accounts payable settlements | 84,228 | |
Loss on mortgage | (8,153) | |
Gain on preferred stock dividends | 37,893 | |
Fresh start valuation adjustments | (28,549) | |
Fair value of equity issued | (827,424) | |
Principal value of Convertible Notes issued | (281,780) | |
Gain on reorganization items, net | $ 2,430,599 | $ 2,430,599 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Concentration Risk (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 85,145 | $ 97,660 | $ 79,462 | $ 87,128 | $ 93,206 | $ 80,892 | $ 84,851 | $ 98,350 | ||||
Successor | Plains Marketing, L.P. | ||||||||||||
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 32,022 | $ 102,182 | $ 117,927 | |||||||||
Percentage of revenue | 32.50% | 29.20% | 33.00% | |||||||||
Successor | Targa Midstream Services L.P. | ||||||||||||
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 35,845 | $ 126,548 | $ 144,583 | |||||||||
Percentage of revenue | 36.40% | 36.20% | 40.50% | |||||||||
Successor | Sinclair Crude Company | ||||||||||||
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 62,623 | |||||||||||
Percentage of revenue | 17.90% | |||||||||||
Predecessor | Plains Marketing, L.P. | ||||||||||||
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 110,370 | |||||||||||
Percentage of revenue | 37.60% | |||||||||||
Predecessor | Targa Midstream Services L.P. | ||||||||||||
Concentration Risk [Line Items] | ||||||||||||
Sales | $ 108,238 | |||||||||||
Percentage of revenue | 36.80% |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Supplemental Disclosure of Cash Flow Information | ||||
Cash paid for reorganization items | $ 0 | $ 0 | $ 0 | |
Cash paid for interest, net of amounts capitalized | (1,183) | (4,045) | (2,438) | |
Cash received (paid) for income taxes | 0 | 4,381 | 4,348 | |
Supplemental Disclosure of Noncash Investing and Financing Activities | ||||
Cumulative effect of adoption of ASU 2015-02 | 0 | 0 | 0 | |
Property, plant and equipment transferred in contract settlement | 0 | 0 | 0 | |
Change in accrued capital expenditures | 10,630 | (15,861) | (28,999) | |
Equity issued for debt | $ (13,001) | $ 0 | $ (268,779) | |
Predecessor | ||||
Supplemental Disclosure of Cash Flow Information | ||||
Cash paid for reorganization items | $ (55,606) | |||
Cash paid for interest, net of amounts capitalized | (104,609) | |||
Cash received (paid) for income taxes | (28) | |||
Supplemental Disclosure of Noncash Investing and Financing Activities | ||||
Cumulative effect of adoption of ASU 2015-02 | (247,566) | |||
Property, plant and equipment transferred in contract settlement | 215,635 | |||
Change in accrued capital expenditures | 25,045 | |||
Equity issued for debt | $ (4,409) |
Acquisitions and Divestitures_2
Acquisitions and Divestitures of Oil and Gas Properties - Divestitures (Details) $ in Thousands | Nov. 01, 2018USD ($)wellshares | Jan. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Oct. 01, 2016USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Successor | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
ARO liabilities settled or disposed | $ 540 | $ 31,967 | $ 11,308 | |||
Payments for contract settlement | 0 | 0 | 0 | |||
Loss on termination of the gathering contract | 0 | 0 | 0 | |||
Revisions in estimated cash flows | $ (12,397) | (870) | 28,565 | |||
Predecessor | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
ARO liabilities settled or disposed | $ 36,979 | |||||
Payments for contract settlement | 11,000 | |||||
Loss on termination of the gathering contract | 90,184 | |||||
Revisions in estimated cash flows | $ 0 | |||||
Predecessor | WTO Properties | Treating Agreement | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Revisions in estimated cash flows | $ 34,100 | |||||
Disposal Group, Not Discontinued Operations | Successor | Central Basin Platform | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Number of common units sold (in shares) | shares | 13,125,000 | |||||
Percent of common equity sold | 25.00% | |||||
Proceeds from sale of oil and natural gas properties | $ 14,500 | |||||
ARO liabilities settled or disposed | $ 26,900 | $ 26,900 | ||||
Number of wells sold | well | 1,066 | |||||
Disposal Group, Not Discontinued Operations | Successor | Oil and Gas Properties | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Proceeds from sale of oil and natural gas properties | $ 17,100 | |||||
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations | Predecessor | WTO Properties | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Payments for contract settlement | $ 11,000 | |||||
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations | Predecessor | WTO Properties | Treating Agreement | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Contract agreement, term | 30 years | |||||
Cumulative shortfall accrued | $ 111,900 | |||||
Loss on termination of the gathering contract | $ 89,100 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures of Oil and Gas Properties - Acquisitions (Details) - Successor $ in Thousands | Nov. 02, 2018USD ($)awell | Feb. 10, 2017USD ($)awell | Dec. 31, 2016USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Oil and Gas Properties Acquisition | |||||
Cash paid for acres | $ | $ 22,500 | $ 47,800 | |||
Liability incurred upon acquiring and drilling wells | $ | $ 6,400 | $ 121 | $ 7,079 | $ 1,336 | |
Number of wells acquired | well | 1,199 | 4 | |||
Percent of wells operated by company | 80.00% | ||||
Percent of working interest in acquired acres | 11.10% | ||||
Number of gross acres acquired | 397,000 | ||||
Number of net acres acquired | 44,000 | ||||
Percent of working interest in saltwater gathering and disposal system | 13.20% | ||||
Number of acres acquired | 13,000 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | $ 5,286 | $ 5,582 |
Commodity derivative contracts | 18,467 | |
Recurring Measurement Basis | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Investments | 5,072 | |
Total Assets | 5,286 | 6,382 |
Netting, assets | 0 | (4,272) |
Netting, liabilities | (4,272) | |
Liabilities at Fair Value | 14,195 | |
Recurring Measurement Basis | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Netting, assets | 0 | (4,272) |
Assets at Fair Value | 5,286 | 1,310 |
Netting, liabilities | (4,272) | |
Liabilities at Fair Value | 14,195 | |
Recurring Measurement Basis | Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Investments | 5,072 | |
Total Assets | 0 | 5,072 |
Commodity derivative contracts | 0 | |
Recurring Measurement Basis | Level 1 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | 0 | 0 |
Commodity derivative contracts | 0 | |
Recurring Measurement Basis | Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Investments | 0 | |
Total Assets | 5,286 | 5,582 |
Commodity derivative contracts | 18,467 | |
Recurring Measurement Basis | Level 2 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | 5,286 | 5,582 |
Commodity derivative contracts | 18,467 | |
Recurring Measurement Basis | Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Investments | 0 | |
Total Assets | 0 | 0 |
Commodity derivative contracts | 0 | |
Recurring Measurement Basis | Level 3 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | $ 0 | 0 |
Commodity derivative contracts | $ 0 |
Fair Value Measurements - Estim
Fair Value Measurements - Estimated Fair Value and Carrying Value of Long-term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 01, 2016 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Carrying Value | $ 0 | $ 37,502 | |
Secured Notes | Building Note | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | $ 36,600 | ||
Carrying Value | 0 | 37,502 | |
Level 2 | Secured Notes | Building Note | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Fair Value | $ 0 | $ 42,526 |
Accounts Receivable - Summary o
Accounts Receivable - Summary of Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Oct. 02, 2016 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Oil, natural gas and NGL sales | $ 31,780 | $ 35,301 | ||
Joint interest billing | 13,083 | 29,505 | ||
Oil and natural gas services | 604 | 639 | ||
Other | 1,331 | 7,106 | ||
Total accounts receivable | 46,798 | 72,551 | ||
Less: allowance for doubtful accounts | (1,295) | (1,274) | ||
Total accounts receivable, net | 45,503 | 71,277 | ||
Successor | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Less: allowance for doubtful accounts | $ (1,295) | $ (1,274) | $ (880) | $ 0 |
Accounts Receivable - Balance a
Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Allowance for Doubtful Accounts Receivable [Roll Forward] | ||||
Beginning balance | $ 1,274 | |||
Ending balance | 1,295 | $ 1,274 | ||
Successor | ||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | ||||
Beginning balance | 1,274 | 880 | ||
Additions charged to costs and expenses | $ 880 | 758 | 397 | |
Deductions | 0 | (737) | (3) | |
Impact of fresh start accounting | 0 | 0 | 0 | |
Ending balance | 880 | $ 1,295 | $ 1,274 | |
Predecessor | ||||
Allowance for Doubtful Accounts Receivable [Roll Forward] | ||||
Beginning balance | $ 0 | $ 4,847 | ||
Additions charged to costs and expenses | 16,695 | |||
Deductions | (751) | |||
Impact of fresh start accounting | 20,791 | |||
Ending balance | $ 0 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties, using full cost method of accounting | |||
Proved | $ 1,269,091 | $ 1,056,806 | $ 840,201 |
Unproved | 60,152 | 100,884 | 74,937 |
Total oil and natural gas properties | 1,329,243 | 1,157,690 | 915,138 |
Less: accumulated depreciation, depletion and impairment | (580,132) | (460,431) | (353,030) |
Net oil and natural gas properties capitalized costs | 749,111 | 697,259 | $ 562,108 |
Property, Plant and Equipment, Net | |||
Total | 226,182 | 241,867 | |
Less accumulated depreciation and amortization | (25,344) | (15,886) | |
Other property, plant and equipment, net | 200,838 | 225,981 | |
Total property, plant and equipment, net | 949,949 | 923,240 | |
Land | |||
Property, Plant and Equipment, Net | |||
Total | 4,400 | 4,500 | |
Electrical infrastructure | |||
Property, Plant and Equipment, Net | |||
Total | 131,176 | 131,010 | |
Non-oil and natural gas equipment | |||
Property, Plant and Equipment, Net | |||
Total | 13,458 | 26,809 | |
Buildings and structures | |||
Property, Plant and Equipment, Net | |||
Total | $ 77,148 | $ 79,548 |
Property, Plant and Equipment -
Property, Plant and Equipment - Narrative (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Jun. 30, 2018USD ($) | Dec. 31, 2016$ / Boe | Oct. 01, 2016$ / Boe | Dec. 31, 2018USD ($)$ / Boe | Dec. 31, 2017USD ($)$ / Boe | Mar. 31, 2018USD ($) | |
Property, Plant and Equipment [Line Items] | ||||||
Assets held for sale | $ 10,600,000 | |||||
Proceeds from sale of property held-for-sale | $ 10,400,000 | |||||
Gain (loss) on sale of assets and asset impairment charges | $ 0 | $ 1,100,000 | ||||
Assets held-for-sale, current, other | $ 5,700,000 | |||||
NRV of assets held-for-sale | $ 1,600,000 | |||||
Impairment recognized | $ 4,100,000 | |||||
Expected completion of evaluation activities on majority of unproved properties | 10 years | |||||
Minimum | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Expect completion of evaluation activities on majority of unproved properties, without existing production | 3 years | |||||
Maximum | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Expect completion of evaluation activities on majority of unproved properties, without existing production | 5 years | |||||
Property Located in Oklahoma City, OK | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Assets held for sale | $ 9,300,000 | |||||
Successor | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Average depreciation and depletion rate (usd per Boe) | $ / Boe | 8.31 | 10.32 | 7.92 | |||
Predecessor | ||||||
Property, Plant and Equipment [Line Items] | ||||||
Average depreciation and depletion rate (usd per Boe) | $ / Boe | 6.05 |
Property, Plant and Equipment_3
Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||||
Property acquisition, cumulative | $ 59,522 | |||
Property acquisition | 3,859 | $ 20,647 | $ 13,735 | $ 21,281 |
Exploration, cumulative | 630 | |||
Exploration | 13 | 323 | 243 | 51 |
Total costs incurred, cumulative | 60,152 | |||
Total costs incurred | $ 3,872 | $ 20,970 | $ 13,978 | $ 21,332 |
Impairment (Details)
Impairment (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Full cost pool ceiling impairments | $ 319,087 | $ 0 | $ 0 | |
Asset impairment charges | $ 319,087 | 4,170 | 4,019 | |
Successor | Drilling assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | 22 | 4,019 | ||
Successor | Electrical infrastructure assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | 0 | 0 | ||
Successor | Midstream assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | $ 4,148 | $ 0 | ||
Predecessor | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Full cost pool ceiling impairments | $ 657,392 | |||
Asset impairment charges | 718,194 | |||
Predecessor | Drilling assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | 3,511 | |||
Predecessor | Electrical infrastructure assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | 55,600 | |||
Predecessor | Midstream assets | ||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | ||||
Asset impairment charges | $ 1,691 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Payables and Accruals [Abstract] | ||
Accounts payable and other accrued expenses | $ 78,219 | $ 90,423 |
Payroll and benefits | 12,891 | 21,475 |
Production payable | 12,767 | 18,059 |
Taxes payable | 5,350 | 3,983 |
Drilling advances | 2,031 | 3,830 |
Accrued interest | 539 | 1,385 |
Total accounts payable and accrued expenses | $ 111,797 | $ 139,155 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Total debt | $ 0 | $ 37,502 |
Less: current maturities of long-term debt | 0 | 0 |
Long-term debt | 0 | 37,502 |
Secured Notes | Building Note | ||
Debt Instrument [Line Items] | ||
Total debt | $ 0 | $ 37,502 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) - USD ($) shares in Millions | Feb. 10, 2017 | Oct. 01, 2016 | Feb. 28, 2017 | Feb. 09, 2017 | Dec. 31, 2016 | May 11, 2017 | May 11, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 31, 2018 |
Debt Instrument [Line Items] | ||||||||||
Face value of long-term debt | $ 0 | $ 37,502,000 | ||||||||
Secured Notes | Building Note | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Face value of long-term debt | 0 | 37,502,000 | ||||||||
Face amount of debt instrument | $ 35,000,000 | |||||||||
Fair value of debt | 36,600,000 | |||||||||
Term of paid in kind interest payments | 90 days | |||||||||
Proceeds from issuance of debt | $ 26,800,000 | |||||||||
Paid-in-kind interest | $ 1,300,000 | |||||||||
Gain on extinguishment of debt | 1,200,000 | |||||||||
Secured Notes | Building Note | October 5, 2016 through October 4, 2017 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Annual interest rate | 6.00% | |||||||||
Secured Notes | Building Note | October 5, 2017 through October 4, 2018 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Annual interest rate | 8.00% | |||||||||
Secured Notes | Building Note | October 5, 2018 and thereafter | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Annual interest rate | 10.00% | |||||||||
Convertible Debt | New Convertible Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Face amount of debt instrument | $ 281,800,000 | |||||||||
Fair value of debt | 445,700,000 | |||||||||
Premium on debt instrument | $ 163,900,000 | |||||||||
Conversion ratio | 0.05330841 | |||||||||
Common stock issued for debt | $ 5,100,000 | $ 13,000,000 | ||||||||
Common stock issued for debt (in shares) | 14.1 | 15 | 0.3 | 0.7 | ||||||
Debt conversion, original debt, amount | $ 263,700,000 | |||||||||
Revolving Credit Facility | New First Lien Exit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 425,000,000 | |||||||||
Cash collateral account | $ 50,000,000 | |||||||||
Revolving Credit Facility | New First Lien Exit Facility | Base Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 3.75% | |||||||||
Revolving Credit Facility | New First Lien Exit Facility | LIBOR | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 4.75% | |||||||||
Variable rate floor | 1.00% | |||||||||
Revolving Credit Facility | New First Lien Exit Facility and New Amended Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Line of credit facility, unused capacity, commitment fee percentage | 0.50% | |||||||||
Revolving Credit Facility | Amended New Credit Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 600,000,000 | |||||||||
Line of credit facility, current borrowing capacity | $ 425,000,000 | $ 350,000,000 | ||||||||
Minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination | 95.00% | |||||||||
Ratio of Indebtedness to Assets | 3.50 | |||||||||
Minimum consolidated interest coverage ratio | 2.25 | |||||||||
Aggregate amount of default trigger | $ 25,000,000 | |||||||||
Legal judgment default trigger | $ 25,000,000 | |||||||||
Face value of long-term debt | 0 | 0 | ||||||||
Letters of credit outstanding | 5,200,000 | |||||||||
Revolving Credit Facility | Amended New Credit Facility | Base Rate | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 2.00% | |||||||||
Revolving Credit Facility | Amended New Credit Facility | Base Rate | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 3.00% | |||||||||
Revolving Credit Facility | Amended New Credit Facility | LIBOR | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 3.00% | |||||||||
Revolving Credit Facility | Amended New Credit Facility | LIBOR | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate | 4.00% | |||||||||
Successor | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Common stock issued for debt | $ 13,001,000 | 0 | 268,779,000 | |||||||
Gain on extinguishment of debt | $ 0 | $ 1,151,000 | $ 0 | |||||||
Successor | Convertible Debt | New Convertible Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Common stock issued for debt (in shares) | 14.1 |
Derivatives - Narrative (Detail
Derivatives - Narrative (Details) bbl in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018USD ($)institution$ / Unit | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Oct. 01, 2016USD ($) | Dec. 31, 2018USD ($)institution$ / Unitbbl | Dec. 31, 2017USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | $ (42,600) | $ 11,300 | $ 30,100 | $ 18,300 | $ 21,900 | $ 11,700 | $ (23,500) | $ (34,200) | ||||
Number of counterparties to open derivative contracts | institution | 4 | 4 | ||||||||||
Commodity Derivatives | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | $ 17,200 | $ (24,100) | ||||||||||
Payments for (proceeds from) settlement of derivative contracts | 35,300 | (7,300) | ||||||||||
Payment for early settlements | 800 | |||||||||||
Successor | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | $ 25,652 | 17,155 | (24,090) | |||||||||
Payments for (proceeds from) settlement of derivative contracts | (7,698) | $ 35,325 | $ (7,260) | |||||||||
Successor | Commodity Derivatives | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | 25,700 | |||||||||||
Payments for (proceeds from) settlement of derivative contracts | $ (7,700) | |||||||||||
Predecessor | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | $ 4,823 | |||||||||||
Payments for (proceeds from) settlement of derivative contracts | (72,608) | |||||||||||
Predecessor | Commodity Derivatives | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Loss (gain) on derivative contracts | 4,800 | |||||||||||
Payments for (proceeds from) settlement of derivative contracts | (72,600) | |||||||||||
Derivative, cash received on early settlement | $ (17,900) | |||||||||||
2018 Production | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Notional (MMcf) | bbl | 9 | |||||||||||
Strike price (in dollars per unit) | $ / Unit | 56.12 | 56.12 | ||||||||||
2019 Production | ||||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||||
Notional (MMcf) | bbl | 5 | |||||||||||
Strike price (in dollars per unit) | $ / Unit | 54.29 | 54.29 |
Derivatives - Offsetting Assets
Derivatives - Offsetting Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
ASSETS | ||
Gross Amounts | $ 5,286 | $ 5,582 |
Gross Amounts Offset | 0 | (4,272) |
Amounts Net of Offset | 5,286 | 1,310 |
Financial Collateral | 0 | 0 |
Net Amount | 5,286 | 1,310 |
LIABILITIES | ||
Gross Amounts | 18,467 | |
Gross Amounts Offset | (4,272) | |
Amounts Net of Offset | 14,195 | |
Financial Collateral | (14,195) | |
Net Amount | 0 | |
Derivative contracts - current | ||
ASSETS | ||
Gross Amounts | 5,286 | 5,582 |
Gross Amounts Offset | 0 | (4,272) |
Amounts Net of Offset | 5,286 | 1,310 |
Financial Collateral | 0 | 0 |
Net Amount | $ 5,286 | 1,310 |
Derivative contracts - current | ||
LIABILITIES | ||
Gross Amounts | 14,899 | |
Gross Amounts Offset | (4,272) | |
Amounts Net of Offset | 10,627 | |
Financial Collateral | (10,627) | |
Net Amount | 0 | |
Derivative contracts - noncurrent | ||
LIABILITIES | ||
Gross Amounts | 3,568 | |
Gross Amounts Offset | 0 | |
Amounts Net of Offset | 3,568 | |
Financial Collateral | (3,568) | |
Net Amount | $ 0 |
Derivatives - Open Commodity De
Derivatives - Open Commodity Derivative Contracts (Details) - Natural Gas Price Swaps, January 2019 - March 2019 | 12 Months Ended |
Dec. 31, 2018$ / McfMMcf | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Notional (MMcf) | MMcf | 4,500 |
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / Mcf | 4.28 |
Derivatives - Fair Value of Der
Derivatives - Fair Value of Derivative Contracts (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value | ||
Derivative assets | $ 5,286 | $ 5,582 |
Derivative liabilities | (18,467) | |
Total net derivative contracts | 5,286 | (12,885) |
Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative assets | 5,286 | 5,582 |
Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative liabilities | (14,899) | |
Derivative contracts - noncurrent | ||
Derivatives, Fair Value | ||
Derivative liabilities | (3,568) | |
Oil price swaps | Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative liabilities | 0 | (14,899) |
Oil price swaps | Derivative contracts - noncurrent | ||
Derivatives, Fair Value | ||
Derivative liabilities | 0 | (3,568) |
Natural gas price swaps | Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative assets | $ 5,286 | $ 5,582 |
Asset Retirement Obligations -
Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) - USD ($) $ in Thousands | Nov. 02, 2018 | Nov. 01, 2018 | Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 |
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Less: current portion | $ 25,393 | $ 41,017 | ||||
Asset retirement obligations, net of current | 34,671 | 36,527 | ||||
Successor | ||||||
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Beginning balance | $ 92,413 | 77,544 | 106,481 | |||
Liability incurred upon acquiring and drilling wells | $ 6,400 | 121 | 7,079 | 1,336 | ||
Revisions in estimated cash flows | 12,397 | 870 | (28,565) | |||
Liability settled or disposed in current period | (540) | (31,967) | (11,308) | |||
Accretion | 2,090 | 6,538 | 9,600 | |||
Impact of fresh start accounting | 0 | 0 | 0 | |||
Ending balance | 106,481 | $ 92,413 | 60,064 | 77,544 | ||
Less: current portion | 66,154 | |||||
Asset retirement obligations, net of current | 40,327 | 34,671 | $ 36,527 | |||
Predecessor | ||||||
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Beginning balance | $ 92,413 | 103,578 | ||||
Liability incurred upon acquiring and drilling wells | 505 | |||||
Revisions in estimated cash flows | 0 | |||||
Liability settled or disposed in current period | (36,979) | |||||
Accretion | 4,365 | |||||
Impact of fresh start accounting | 20,944 | |||||
Ending balance | 92,413 | |||||
Less: current portion | 65,678 | |||||
Asset retirement obligations, net of current | 26,735 | |||||
Predecessor | WTO Properties | ||||||
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Liability settled or disposed in current period | $ (34,100) | |||||
Central Basin Platform | Disposal Group, Not Discontinued Operations | Successor | ||||||
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Liability settled or disposed in current period | $ (26,900) | $ (26,900) |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | Dec. 31, 2018USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Third-party drilling rig agreements | $ 3.6 |
Leases and other agreements | $ 4.8 |
Equity - Additional Information
Equity - Additional Information (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Class of Stock [Line Items] | ||
Common stock, issued (in shares) | 35,687,000 | 35,650,000 |
Common stock, outstanding (in shares) | 35,687,000 | 35,650,000 |
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Nonvested (in shares) | 400,000 | |
Shares authorized (in shares) | 250,000,000 | 250,000,000 |
Class of Warrant, Number of Securities issued for Each Warrant | 1 | |
Series A Warrants | ||
Class of Stock [Line Items] | ||
Issuance of common stock (in shares) | 4,600,000 | |
Exercise price of warrants (in usd per share) | $ 41.34 | |
Series B Warrants | ||
Class of Stock [Line Items] | ||
Issuance of common stock (in shares) | 2,000,000 | |
Exercise price of warrants (in usd per share) | $ 42.03 |
Equity - Shares Withheld for Ta
Equity - Shares Withheld for Taxes (Details) - Treasury Stock - Successor - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares withheld for taxes | 5 | 495 | 349 |
Value of shares withheld for taxes | $ 110 | $ 7,420 | $ 6,730 |
Equity - Preferred Stock Divide
Equity - Preferred Stock Dividends (Details) - Predecessor $ in Thousands | 9 Months Ended |
Oct. 01, 2016USD ($) | |
8.5% Convertible perpetual preferred stock | |
Class of Stock [Line Items] | |
Dividend rate, percentage | 8.50% |
Dividends in arrears | $ 11,262 |
7.0% Convertible perpetual preferred stock | |
Class of Stock [Line Items] | |
Dividend rate, percentage | 7.00% |
Dividends in arrears | $ 21,000 |
Share Based Compensation - Narr
Share Based Compensation - Narrative (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Oct. 31, 2016$ / Unit | Dec. 31, 2016USD ($)shares | Mar. 31, 2016USD ($)shares | Oct. 01, 2016USD ($)shares | Dec. 31, 2018USD ($)shares | Dec. 31, 2017USD ($)shares | Feb. 28, 2017shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares authorized (in shares) | shares | 4,600,000 | ||||||
Predecessor | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation cost related to unvested awards | $ 5,900 | ||||||
Share-based compensation expense | 11,200 | ||||||
Share-based compensation, capitalized | 1,700 | ||||||
Severance, compensation cost of accelerated shares | $ 5,119 | ||||||
Severance, number of accelerated shares (in shares) | shares | 1,240,000 | ||||||
Predecessor | Restricted Stock | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Vesting period (in years) | 4 years | ||||||
Severance, compensation cost of accelerated shares | $ 5,400 | ||||||
Severance, number of accelerated shares (in shares) | shares | 1,300,000 | ||||||
Successor | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Severance, compensation cost of accelerated shares | $ 4,286 | $ 13,131 | $ 1,825 | ||||
Severance, number of accelerated shares (in shares) | shares | 191,000 | 763,000 | 96,000 | ||||
Successor | Restricted Stock | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation cost related to unvested awards | $ 4,700 | ||||||
Period of recognition for unrecognized costs | 2 years 2 months 12 days | ||||||
Aggregate intrinsic value of restricted stock vested during period | $ 16,000 | ||||||
Successor | Performance Shares | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Aggregate intrinsic value of restricted stock vested during period | 2,700 | ||||||
Performance share plan, conversion to common stock (in shares) | shares | 1 | ||||||
Successor | Performance Units | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Aggregate intrinsic value of restricted stock vested during period | $ 4,800 | ||||||
Weighted average grant date fair value | $ / Unit | 100 | ||||||
Minimum | Successor | Restricted Stock | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Vesting period (in years) | 1 year | ||||||
Maximum | Successor | Restricted Stock | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Vesting period (in years) | 3 years |
Share Based Compensation - Summ
Share Based Compensation - Summary of Unvested Restricted Stock Awards (Details) - $ / shares | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2015 | |
Number of Shares | |||||
Unvested shares/units outstanding at end of period (in shares) | 400,000 | ||||
Successor | Restricted Stock | |||||
Number of Shares | |||||
Unvested shares/units outstanding at beginning of period (in shares) | 0 | 1,105,000 | 1,407,000 | ||
Granted (in shares) | 1,448,000 | 370,000 | 671,000 | ||
Vested (in shares) | (14,000) | (1,066,000) | (827,000) | ||
Forfeited / Canceled (in shares) | (27,000) | (44,000) | (146,000) | ||
Unvested shares/units outstanding at end of period (in shares) | 1,407,000 | 0 | 365,000 | 1,105,000 | |
Weighted- Average Grant Date Fair Value (usd per share) | |||||
Unvested shares/units outstanding (in usd per share) | $ 24.32 | $ 0 | $ 16.07 | $ 22.62 | |
Granted (in usd per share) | 24.32 | 16 | 19.97 | ||
Vested (in usd per share) | 24.32 | 22.63 | 23.23 | ||
Forfeited / Canceled (in usd per share) | $ 24.32 | $ 21.04 | $ 23.52 | ||
Successor | Performance Shares | |||||
Number of Shares | |||||
Unvested shares/units outstanding at beginning of period (in shares) | 183,000 | 0 | |||
Granted (in shares) | 111,000 | 199,000 | |||
Vested (in shares) | (177,000) | 0 | |||
Forfeited / Canceled (in shares) | (6,000) | (16,000) | |||
Unvested shares/units outstanding at end of period (in shares) | 0 | 111,000 | 183,000 | ||
Weighted- Average Grant Date Fair Value (usd per share) | |||||
Unvested shares/units outstanding (in usd per share) | $ 20.41 | ||||
Granted (in usd per share) | |||||
Vested (in usd per share) | |||||
Forfeited / Canceled (in usd per share) | |||||
Successor | Performance Units | |||||
Number of Shares | |||||
Unvested shares/units outstanding at beginning of period (in shares) | 0 | 49,000 | 87,000 | ||
Granted (in shares) | 97,000 | 0 | 0 | ||
Vested (in shares) | (1,000) | (48,000) | (32,000) | ||
Forfeited / Canceled (in shares) | (9,000) | (1,000) | (6,000) | ||
Unvested shares/units outstanding at end of period (in shares) | 87,000 | 0 | 0 | 49,000 | |
Weighted- Average Grant Date Fair Value (usd per share) | |||||
Unvested shares/units outstanding (in usd per share) | $ 0 | ||||
Granted (in usd per share) | |||||
Vested (in usd per share) | |||||
Forfeited / Canceled (in usd per share) | |||||
Predecessor | Restricted Stock | |||||
Number of Shares | |||||
Unvested shares/units outstanding at beginning of period (in shares) | 0 | 5,626,000 | |||
Granted (in shares) | 0 | ||||
Vested (in shares) | (3,034,000) | ||||
Forfeited / Canceled (in shares) | (2,592,000) | ||||
Unvested shares/units outstanding at end of period (in shares) | 0 | ||||
Weighted- Average Grant Date Fair Value (usd per share) | |||||
Unvested shares/units outstanding (in usd per share) | $ 0 | $ 4.85 | |||
Granted (in usd per share) | 0 | ||||
Vested (in usd per share) | 5.34 | ||||
Forfeited / Canceled (in usd per share) | $ 4.31 |
Share Based Compensation - Shar
Share Based Compensation - Share-based Compensation Expense (Details) - Successor - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 6,581 | $ 24,276 | $ 17,912 |
Performance units | 1,265 | 4,774 | 2,574 |
Total share and incentive-based compensation expense | 7,846 | 29,050 | 20,486 |
Less: Capitalized compensation expense | (407) | (1,037) | (2,521) |
Share and incentive-based compensation expense, net | 7,439 | 28,013 | 17,965 |
Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 2,296 | 5,354 | 16,087 |
Performance units | 528 | 756 | 2,574 |
Total share and incentive-based compensation expense | 2,824 | 6,110 | 18,661 |
Less: Capitalized compensation expense | (407) | (482) | (2,521) |
Share and incentive-based compensation expense, net | 2,417 | 5,628 | 16,140 |
Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 9,196 | 1,825 |
Performance units | 0 | 2,151 | 0 |
Total share and incentive-based compensation expense | 0 | 11,347 | 1,825 |
Less: Capitalized compensation expense | 0 | 0 | 0 |
Share and incentive-based compensation expense, net | 0 | 11,347 | 1,825 |
Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 4,285 | 3,935 | 0 |
Performance units | 737 | 558 | 0 |
Total share and incentive-based compensation expense | 5,022 | 4,493 | 0 |
Less: Capitalized compensation expense | 0 | 0 | 0 |
Share and incentive-based compensation expense, net | 5,022 | 4,493 | 0 |
Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 5,791 | 0 |
Performance units | 0 | 1,309 | 0 |
Total share and incentive-based compensation expense | 0 | 7,100 | 0 |
Less: Capitalized compensation expense | 0 | (555) | 0 |
Share and incentive-based compensation expense, net | 0 | 6,545 | 0 |
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 6,581 | 21,833 | 16,556 |
Restricted Stock | Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 2,296 | 4,735 | 14,731 |
Restricted Stock | Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 8,140 | 1,825 |
Restricted Stock | Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 4,285 | 3,777 | 0 |
Restricted Stock | Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 0 | 5,181 | 0 |
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 2,443 | 1,356 | |
Performance Shares | Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 619 | 1,356 | |
Performance Shares | Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 1,056 | 0 | |
Performance Shares | Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 158 | 0 | |
Performance Shares | Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 610 | $ 0 |
Incentive and Deferred Compen_2
Incentive and Deferred Compensation Plans (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 31, 2016 | |
Annual Incentive Plan | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Accrued bonuses | $ 6.6 | |||||||
Payments to employees | $ 8.7 | |||||||
Annual Incentive Plan | Minimum | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Incentive plans, payout percentages of target values | 0.00% | |||||||
Annual Incentive Plan | Maximum | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Incentive plans, payout percentages of target values | 200.00% | |||||||
Performance Incentive Plan | Minimum | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Incentive plans, payout percentages of target values | 0.00% | |||||||
Performance Incentive Plan | Maximum | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Incentive plans, payout percentages of target values | 200.00% | |||||||
Successor | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Deferred compensation plan assets to be distributed to participants | $ 5.1 | |||||||
Successor | Other Postretirement Benefits Plan | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Retirement plan, employer matching contribution, percent of match | 100.00% | 100.00% | 100.00% | |||||
Retirement plan, employer matching contribution, percent of employees' gross pay (up to) | 10.00% | 10.00% | 10.00% | |||||
Retirement plan, employer matching contribution, vesting period | 4 years | 4 years | 4 years | |||||
Retirement plan, cost recognized | $ 0.9 | $ 2.8 | $ 3.6 | |||||
Percent of employee contributions vesting immediately | 100.00% | 100.00% | 100.00% | |||||
Successor | Performance Incentive Plan | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Payments to employees | $ 15.8 | $ 7.1 | ||||||
Predecessor | Other Postretirement Benefits Plan | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Retirement plan, employer matching contribution, percent of match | 100.00% | |||||||
Retirement plan, employer matching contribution, percent of employees' gross pay (up to) | 10.00% | |||||||
Retirement plan, employer matching contribution, vesting period | 4 years | |||||||
Retirement plan, cost recognized | $ 4.9 | |||||||
Percent of employee contributions vesting immediately | 100.00% | |||||||
Predecessor | Performance Incentive Plan | ||||||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||||||
Payments to employees | $ 17.8 |
Revenues - Disaggregation of Re
Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 98,456 | $ 349,395 | $ 357,299 | |
Predecessor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 293,809 | |||
Oil | Successor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 57,093 | 214,651 | 202,539 | |
Oil | Predecessor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 159,023 | |||
NGL | Successor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 14,756 | 67,111 | 61,322 | |
NGL | Predecessor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 42,541 | |||
Natural gas | Successor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 26,458 | 66,964 | 92,349 | |
Natural gas | Predecessor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 78,407 | |||
Other | Successor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 149 | $ 669 | $ 1,089 | |
Other | Predecessor | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 13,838 |
Revenues - Additional Informati
Revenues - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Revenue Receivable from Contract with Customer | |||
Disaggregation of Revenue [Line Items] | |||
Accounts receivable, gross | $ 31.8 | $ 35.3 | $ 42.6 |
Proxy Contest (Details)
Proxy Contest (Details) $ in Millions | 3 Months Ended |
Jun. 30, 2018USD ($)director | |
Other Income and Expenses [Abstract] | |
Number of directors | director | 8 |
Proxy contest | $ | $ 7.2 |
Employee Termination Benefits_2
Employee Termination Benefits (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Mar. 31, 2018 | Jun. 30, 2017 | Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Total Employee Termination Benefits | $ 31,600 | $ 4,400 | ||||
Successor | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | $ 8,048 | $ 19,526 | $ 2,990 | |||
Share-Based Compensation | $ 4,286 | $ 13,131 | $ 1,825 | |||
Number of Shares (in shares) | 191 | 763 | 96 | |||
Total Employee Termination Benefits | $ 12,334 | $ 32,657 | $ 4,815 | |||
Successor | Executive Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 0 | 11,945 | 2,500 | |||
Share-Based Compensation | $ 1,591 | $ 9,196 | $ 1,825 | |||
Number of Shares (in shares) | 73 | 554 | 96 | |||
Total Employee Termination Benefits | $ 1,591 | $ 21,141 | $ 4,325 | |||
Successor | Other Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 8,048 | 7,581 | 490 | |||
Share-Based Compensation | $ 2,695 | $ 3,935 | $ 0 | |||
Number of Shares (in shares) | 118 | 209 | 0 | |||
Total Employee Termination Benefits | $ 10,743 | $ 11,516 | $ 490 | |||
Predecessor | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | $ 13,237 | |||||
Share-Based Compensation | $ 5,119 | |||||
Number of Shares (in shares) | 1,240 | |||||
Total Employee Termination Benefits | $ 18,356 | |||||
Predecessor | Executive Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 810 | |||||
Share-Based Compensation | $ 1,072 | |||||
Number of Shares (in shares) | 299 | |||||
Total Employee Termination Benefits | $ 1,882 | |||||
Predecessor | Other Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 12,427 | |||||
Share-Based Compensation | $ 4,047 | |||||
Number of Shares (in shares) | 941 | |||||
Total Employee Termination Benefits | $ 16,474 |
Income Taxes - (Benefit) Provis
Income Taxes - (Benefit) Provision for Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Current | ||||
Federal | $ 0 | $ (33) | $ (8,719) | |
State | 9 | (38) | (30) | |
Current, total | 9 | (71) | (8,749) | |
Deferred | ||||
Federal | 0 | 0 | 0 | |
State | 0 | 0 | 0 | |
Deferred, total | 0 | 0 | 0 | |
Total (benefit) provision | $ 9 | $ (71) | $ (8,749) | |
Predecessor | ||||
Current | ||||
Federal | $ 0 | |||
State | 11 | |||
Current, total | 11 | |||
Deferred | ||||
Federal | 0 | |||
State | 0 | |||
Deferred, total | 0 | |||
Total (benefit) provision | $ 11 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of (Benefit) Provision for Income Taxes at Statutory Federal Tax Rate to Company's Actual Income Tax (Benefit) Provision (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Reconciliation Of Provision Of Income Taxes [Line Items] | ||||
Computed at federal statutory rate | $ (116,891) | $ (1,921) | $ 13,409 | |
State taxes, net of federal benefit | (3,696) | 119 | (284) | |
Non-deductible expenses | 144 | 849 | 1,711 | |
Non-deductible debt costs | 0 | 0 | 0 | |
Stock-based compensation | 306 | 1,874 | 1,109 | |
Discharge of debt and other reorganization related items | 0 | 206 | 1,018 | |
Return to provision adjustments | 0 | (1,292) | 341,681 | |
Impact of legislative changes | 0 | 0 | 243,801 | |
Release of valuation allowance | 0 | 0 | (8,719) | |
Change in valuation allowance | 120,144 | 132 | (602,452) | |
Other | 2 | (38) | (23) | |
Total (benefit) provision | $ 9 | $ (71) | $ (8,749) | |
Predecessor | ||||
Reconciliation Of Provision Of Income Taxes [Line Items] | ||||
Computed at federal statutory rate | $ 504,283 | |||
State taxes, net of federal benefit | 10,512 | |||
Non-deductible expenses | 462 | |||
Non-deductible debt costs | 22,694 | |||
Stock-based compensation | 5,884 | |||
Discharge of debt and other reorganization related items | 359,278 | |||
Return to provision adjustments | 0 | |||
Impact of legislative changes | 0 | |||
Release of valuation allowance | 0 | |||
Change in valuation allowance | (903,102) | |||
Other | 0 | |||
Total (benefit) provision | $ 11 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2018 | Oct. 04, 2016 | |
Operating Loss Carryforwards [Line Items] | |||
Income tax expense due to TCJA | $ 243.8 | ||
Subject to limitation | $ 1,900 | ||
Expected to expire | $ 1,600 | ||
Domestic Tax Authority | |||
Operating Loss Carryforwards [Line Items] | |||
Federal net operating loss carryovers | 1,100 | ||
Operating loss carryforwards, subject to expiration | 800 | ||
Operating loss carryforwards, not subject to expiration | 300 | ||
Tax credits, not subject to expiration | $ 32 |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax liabilities | ||
Investments | $ 112,343 | $ 171,517 |
Derivative contracts | 1,128 | 0 |
Total deferred tax liabilities | 113,471 | 171,517 |
Deferred tax assets | ||
Property, plant and equipment | 267,865 | 391,273 |
Derivative contracts | 0 | 3,131 |
Net operating loss carryforwards | 302,190 | 217,259 |
Tax credits and other carryforwards | 35,640 | 33,001 |
Asset retirement obligations | 15,016 | 18,843 |
Other | 3,816 | 8,959 |
Total deferred tax assets | 624,527 | 672,466 |
Valuation allowance | (511,056) | (500,949) |
Net deferred tax liability | $ 0 | $ 0 |
Income Taxes - Unrecognized Tax
Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of Unrecognized Tax Benefits | ||
Unrecognized tax benefit at January 1 | $ 48 | $ 84 |
Changes to unrecognized tax benefits related to a prior period | 0 | 2 |
Lapse of statute of limitations | (48) | (38) |
Unrecognized tax benefit at December 31 | $ 0 | $ 48 |
Income Taxes - Periods Open to
Income Taxes - Periods Open to Tax Examination (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum | |
Income Tax Contingency [Line Items] | |
Number of tax years open for state tax audit (in years) | 3 years |
Maximum | |
Income Tax Contingency [Line Items] | |
Number of tax years open for state tax audit (in years) | 5 years |
(Loss) Earnings per Share - Cal
(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
(Loss) Earnings Per Share, Basic (in dollars per share) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (0.54) | $ (0.25) | $ 0.69 | $ 1.90 | ||||
Effect of dilutive securities | ||||||||||||
(Loss) Earnings Per Share, Diluted (in dollars per share) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (0.54) | $ (0.25) | $ 0.69 | $ 1.90 | ||||
Successor | ||||||||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
Net (Loss) Income | $ (333,982) | $ (9,075) | $ 47,062 | |||||||||
Weighted Average Shares, basic (in shares) | 18,967,000 | 35,057,000 | 32,442,000 | |||||||||
(Loss) Earnings Per Share, Basic (in dollars per share) | $ (17.61) | $ (0.26) | $ 1.45 | |||||||||
Effect of dilutive securities | ||||||||||||
Net (Loss) Income, Restricted stock | $ 0 | $ 0 | $ 0 | |||||||||
Weighted Average Shares, Restricted stock awards (in shares) | 0 | 0 | 221,000 | |||||||||
Net (Loss) Income, Performance share units | $ 0 | $ 0 | ||||||||||
Weighted Average Shares, Performance share units (in shares) | 0 | 0 | ||||||||||
Net (Loss) Income, Warrants | $ 0 | $ 0 | $ 0 | |||||||||
Weighted Average Shares, Warrants (in shares) | 0 | 0 | 0 | |||||||||
Net (Loss) Income, Convertible notes | $ 0 | |||||||||||
Weighted Average Shares, Convertible notes (in shares) | 0 | |||||||||||
Net (Loss) Income, Diluted | $ (333,982) | $ (9,075) | $ 47,062 | |||||||||
Weighted Average Shares, Diluted (in shares) | 18,967,000 | 35,057,000 | 32,663,000 | |||||||||
(Loss) Earnings Per Share, Diluted (in dollars per share) | $ (17.61) | $ (0.26) | $ 1.44 | |||||||||
Successor | Warrants | ||||||||||||
Effect of dilutive securities | ||||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | 0 | |||||||||
Successor | Performance Share Units | ||||||||||||
Effect of dilutive securities | ||||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | ||||||||||
Successor | Restricted Stock | ||||||||||||
Effect of dilutive securities | ||||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | ||||||||||
Successor | New Convertible Notes | ||||||||||||
Effect of dilutive securities | ||||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 14,600,000 | |||||||||||
Predecessor | ||||||||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||||||||
Net (Loss) Income | $ 1,424,476 | |||||||||||
Weighted Average Shares, basic (in shares) | 708,928,000 | |||||||||||
(Loss) Earnings Per Share, Basic (in dollars per share) | $ 2.01 | |||||||||||
Effect of dilutive securities | ||||||||||||
Net (Loss) Income, Restricted stock | $ 0 | |||||||||||
Weighted Average Shares, Restricted stock awards (in shares) | 0 | |||||||||||
Net (Loss) Income, Diluted | $ 1,424,476 | |||||||||||
Weighted Average Shares, Diluted (in shares) | 708,928,000 | |||||||||||
(Loss) Earnings Per Share, Diluted (in dollars per share) | $ 2.01 | |||||||||||
Predecessor | Restricted Stock | ||||||||||||
Effect of dilutive securities | ||||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 |
Supplemental Information on O_3
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties | |||
Proved | $ 1,269,091 | $ 1,056,806 | $ 840,201 |
Unproved | 60,152 | 100,884 | 74,937 |
Total oil and natural gas properties | 1,329,243 | 1,157,690 | 915,138 |
Less: accumulated depreciation, depletion and impairment | (580,132) | (460,431) | (353,030) |
Net oil and natural gas properties capitalized costs | $ 749,111 | $ 697,259 | $ 562,108 |
Supplemental Information on O_4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Acquisitions of properties | ||||
Proved | $ 5,142 | $ 30,641 | $ 7,092 | |
Unproved | 5,491 | 4,197 | 91,139 | |
Exploration | 0 | 1,940 | 8,850 | |
Development | 27,429 | 158,361 | 187,264 | |
Total cost incurred | $ 38,062 | $ 195,139 | $ 294,345 | |
Predecessor | ||||
Acquisitions of properties | ||||
Proved | $ 3,897 | |||
Unproved | 1,899 | |||
Exploration | 1,234 | |||
Development | 149,924 | |||
Total cost incurred | $ 156,954 |
Supplemental Information on O_5
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Successor | ||||
Results of Operations for Oil and Gas Producing Activities | ||||
Revenues | $ 98,456 | $ 349,395 | $ 357,299 | |
Expenses | ||||
Production costs | 27,640 | 112,173 | 116,372 | |
Depreciation and depletion | 36,061 | 127,281 | 118,035 | |
Impairment | 319,087 | 0 | 0 | |
Total expenses | 382,788 | 239,454 | 234,407 | |
Income (loss) before income taxes | (284,481) | 109,272 | 121,803 | |
Income tax expense (benefit) | (112,427) | 28,520 | 47,722 | |
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) | (172,054) | 80,752 | 74,081 | |
Predecessor | ||||
Results of Operations for Oil and Gas Producing Activities | ||||
Revenues | $ 293,809 | |||
Expenses | ||||
Production costs | 135,715 | |||
Depreciation and depletion | 90,978 | |||
Impairment | 657,392 | |||
Total expenses | 884,085 | |||
Income (loss) before income taxes | (604,114) | |||
Income tax expense (benefit) | (229,986) | |||
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) | (374,128) | |||
Oil, natural gas and NGL | Successor | ||||
Results of Operations for Oil and Gas Producing Activities | ||||
Revenues | $ 98,307 | $ 348,726 | $ 356,210 | |
Oil, natural gas and NGL | Predecessor | ||||
Results of Operations for Oil and Gas Producing Activities | ||||
Revenues | $ 279,971 |
Supplemental Information on O_6
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details) Mcf in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Dec. 31, 2016MBoeMBblsMcf | Oct. 01, 2016MBoeMcfMBbls | Dec. 31, 2018MBoeMBblsMcf | Dec. 31, 2017MBoeMcfMBbls | Dec. 31, 2016MBoeMBblsMcf | Dec. 31, 2015MBoeMBblsMcf | |
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, Beginning balance (MBoe) | MBoe | 177,600 | |||||
Revisions of previous estimates (MBoe) | MBoe | (24,900) | 10,900 | (105,400) | |||
Acquisitions of new reserves (MBoe) | MBoe | 15,400 | |||||
Extensions and discoveries (MBoe) | MBoe | 19,300 | 19,400 | 7,800 | |||
Sales of reserves in place (MBoe) | MBoe | (6,600) | (1,900) | (24,600) | |||
Proved developed and undeveloped reserves, Ending balance (MBoe) | MBoe | 160,200 | 177,600 | ||||
Predecessor | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, Beginning balance (MBoe) | MBoe | 137,992 | 324,626 | 324,626 | |||
Adoption of ASU 2015-02 (MBoe) | MBoe | (19,084) | |||||
Revisions of previous estimates (MBoe) | MBoe | (130,709) | |||||
Extensions and discoveries (MBoe) | MBoe | 2,785 | |||||
Sales of reserves in place (MBoe) | MBoe | (24,598) | |||||
Production (MBoe) | MBoe | (15,027) | |||||
Proved developed and undeveloped reserves, Ending balance (MBoe) | MBoe | 137,992 | |||||
Proved developed reserves (MBoe) | MBoe | 126,121 | 260,498 | ||||
Proved undeveloped reserves (MBoe) | MBoe | 11,872 | 64,129 | ||||
Predecessor | Oil | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 27,252 | 77,911 | 77,911 | |||
Adoption of ASU 2015-02 | (6,971) | |||||
Revisions of previous estimates | (39,973) | |||||
Extensions and discoveries | 987 | |||||
Sales of reserves in place | (387) | |||||
Production | (4,315) | |||||
Proved developed and undeveloped reserves, ending balance | 27,252 | |||||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 24,541 | 48,639 | ||||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 2,711 | 29,272 | ||||
Predecessor | Oil | Non-controlling Interest | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 7,004 | 7,004 | ||||
Predecessor | NGL | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 33,019 | 61,075 | 61,075 | |||
Adoption of ASU 2015-02 | (3,695) | |||||
Revisions of previous estimates | (21,475) | |||||
Extensions and discoveries | 472 | |||||
Sales of reserves in place | 0 | |||||
Production | (3,358) | |||||
Proved developed and undeveloped reserves, ending balance | 33,019 | |||||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 30,238 | 51,089 | ||||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 2,781 | 9,986 | ||||
Predecessor | NGL | Non-controlling Interest | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 3,694 | 3,694 | ||||
Predecessor | Natural gas | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 466,328 | 1,113,840 | 1,113,840 | |||
Adoption of ASU 2015-02 | Mcf | (50,508) | |||||
Revisions of previous estimates | Mcf | (415,568) | |||||
Extensions and discoveries | Mcf | 7,955 | |||||
Sales of reserves in place | Mcf | (145,267) | |||||
Production | Mcf | (44,124) | |||||
Proved developed and undeveloped reserves, ending balance | Mcf | 466,328 | |||||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 428,050 | 964,617 | ||||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 38,278 | 149,223 | ||||
Predecessor | Natural gas | Non-controlling Interest | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 50,508 | 50,508 | ||||
Successor | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, Beginning balance (MBoe) | MBoe | 177,594 | 163,955 | ||||
Revisions of previous estimates (MBoe) | MBoe | 25,270 | (33,188) | 10,879 | |||
Acquisitions of new reserves (MBoe) | MBoe | 15,350 | 202 | ||||
Extensions and discoveries (MBoe) | MBoe | 5,034 | 19,332 | 19,373 | |||
Sales of reserves in place (MBoe) | MBoe | (6,577) | (1,909) | ||||
Production (MBoe) | MBoe | (4,341) | (12,335) | (14,906) | |||
Proved developed and undeveloped reserves, Ending balance (MBoe) | MBoe | 163,955 | 160,176 | 177,594 | 163,955 | ||
Proved developed reserves (MBoe) | MBoe | 120,706 | 92,303 | 123,765 | 120,706 | ||
Proved undeveloped reserves (MBoe) | MBoe | 43,249 | 67,873 | 53,829 | 43,249 | ||
Successor | Oil | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 61,791 | 52,884 | ||||
Revisions of previous estimates | 23,978 | (2,316) | 804 | |||
Acquisitions of new reserves | 2,146 | 18 | ||||
Extensions and discoveries | 2,868 | 11,148 | 12,446 | |||
Sales of reserves in place | (5,273) | (204) | ||||
Production | (1,214) | (3,477) | (4,157) | |||
Proved developed and undeveloped reserves, ending balance | 52,884 | 64,019 | 61,791 | 52,884 | ||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 25,911 | 18,693 | 25,845 | 25,911 | ||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 26,973 | 45,326 | 35,946 | 26,973 | ||
Successor | NGL | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | 34,314 | 33,607 | ||||
Revisions of previous estimates | 1,139 | (8,952) | 2,628 | |||
Acquisitions of new reserves | 4,131 | 70 | ||||
Extensions and discoveries | 448 | 2,320 | 1,914 | |||
Sales of reserves in place | (809) | (529) | ||||
Production | (999) | (2,829) | (3,376) | |||
Proved developed and undeveloped reserves, ending balance | 33,607 | 28,175 | 34,314 | 33,607 | ||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 29,290 | 22,302 | 29,922 | 29,290 | ||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 4,317 | 5,873 | 4,392 | 4,317 | ||
Successor | Natural gas | ||||||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | ||||||
Proved developed and undeveloped reserves, beginning balance | Mcf | 488,932 | 464,782 | ||||
Revisions of previous estimates | Mcf | 915 | (131,518) | 44,679 | |||
Acquisitions of new reserves | Mcf | 54,436 | 683 | ||||
Extensions and discoveries | Mcf | 10,309 | 35,185 | 30,080 | |||
Sales of reserves in place | Mcf | (2,969) | (7,055) | ||||
Production | Mcf | (12,770) | (36,175) | (44,237) | |||
Proved developed and undeveloped reserves, ending balance | Mcf | 464,782 | 407,891 | 488,932 | 464,782 | ||
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 393,028 | 307,845 | 407,988 | 393,028 | ||
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 71,754 | 100,046 | 80,944 | 71,754 |
Supplemental Information on O_7
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Calculation of Weighted Average Per Unit Prices (Unaudited) (Details) - Successor | 12 Months Ended | ||
Dec. 31, 2018$ / bbl$ / Mcf | Dec. 31, 2017$ / bbl$ / Mcf | Dec. 31, 2016$ / Mcf$ / bbl | |
Oil | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | 60.86 | 48.47 | 38.59 |
NGL | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | 25.62 | 20.28 | 10.99 |
Natural gas | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf | 1.77 | 1.90 | 1.56 |
Supplemental Information on O_8
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Dec. 31, 2016MBoe | Oct. 01, 2016MBoe | Dec. 31, 2018MBoe | Dec. 31, 2017MBoe | Dec. 31, 2016MBoewell | Dec. 31, 2015MBoe | |
Reserve Quantities [Line Items] | ||||||
Percentage of proved reserves estimates prepared by external engineers | 0.90 | |||||
Proved developed and undeveloped reserves (MBoe) | 160,200 | 177,600 | ||||
Revision of previous estimates (MBoe) | (24,900) | 10,900 | (105,400) | |||
Revision of previous estimates due to changes in well performance (MBoe) | (8,300) | (94,700) | ||||
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) | 6,600 | 1,900 | 24,600 | |||
Acquisitions of new reserves (MBoe) | 15,400 | |||||
Upward revision of estimates due to extensions (MBoe) | 19,300 | 19,400 | 7,800 | |||
Revision of previous estimates due to changes in commodity pricing (MBoe) | (12,100) | |||||
Decrease in reserves due to changes in accounting | (19,100) | |||||
Natural Gas and LNG | ||||||
Reserve Quantities [Line Items] | ||||||
Percent share of downward revision | (85.00%) | |||||
Oil | ||||||
Reserve Quantities [Line Items] | ||||||
Percent share of downward revision | (15.00%) | |||||
Mid-Continent | ||||||
Reserve Quantities [Line Items] | ||||||
Minimum number of wells in areas with decline in production | well | 3 | |||||
Number of years wells in production seeing decline in production | 2 years | |||||
Successor | ||||||
Reserve Quantities [Line Items] | ||||||
Proved developed and undeveloped reserves (MBoe) | 163,955 | 160,176 | 177,594 | 163,955 | ||
Revision of previous estimates (MBoe) | 25,270 | (33,188) | 10,879 | |||
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) | 6,577 | 1,909 | ||||
Acquisitions of new reserves (MBoe) | 15,350 | 202 | ||||
Upward revision of estimates due to extensions (MBoe) | 5,034 | 19,332 | 19,373 | |||
Predecessor | ||||||
Reserve Quantities [Line Items] | ||||||
Proved developed and undeveloped reserves (MBoe) | 137,992 | 324,626 | ||||
Revision of previous estimates (MBoe) | (130,709) | |||||
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) | 24,598 | |||||
Upward revision of estimates due to extensions (MBoe) | 2,785 |
Supplemental Information on O_9
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Extractive Industries [Abstract] | |||
Future cash inflows from production | $ 5,339,265 | $ 4,621,615 | $ 3,136,762 |
Future production costs | (1,996,689) | (1,837,852) | (1,454,798) |
Future development costs | (1,170,113) | (966,203) | (665,516) |
Future income tax expenses | 0 | (107) | (142) |
Undiscounted future net cash flows | 2,172,463 | 1,817,453 | 1,016,306 |
10% annual discount | (1,126,860) | (1,068,159) | (577,942) |
Standardized measure of discounted future net cash flows | $ 1,045,603 | $ 749,294 | $ 438,364 |
Supplemental Information on _10
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Oct. 01, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||
Beginning present value | $ 749,294 | $ 438,364 | ||
Changes during the year | ||||
Ending present value(2) | $ 438,364 | 1,045,603 | 749,294 | |
Successor | ||||
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||
Beginning present value | 392,604 | 749,294 | 438,364 | |
Changes during the year | ||||
Adoption of ASU 2015-02 | 0 | 0 | 0 | |
Revenues less production | (70,668) | (236,553) | (239,838) | |
Net changes in prices, production and other costs | 35,684 | 316,095 | 347,458 | |
Development costs incurred | 7,941 | 80,050 | 35,517 | |
Net changes in future development costs | (291,232) | (11,483) | (64,484) | |
Extensions and discoveries | 14,986 | 102,961 | 112,556 | |
Revisions of previous quantity estimates | 308,374 | (91,038) | 26,697 | |
Accretion of discount | 9,375 | 70,576 | 37,226 | |
Net change in income taxes | 0 | 56 | 23 | |
Purchases of reserves in-place | 0 | 35,713 | 454 | |
Sales of reserves in-place | 0 | (2,029) | (2,977) | |
Timing differences and other | 31,300 | 31,961 | 58,298 | |
Net change for the year | 45,760 | 296,309 | 310,930 | |
Ending present value(2) | 438,364 | $ 392,604 | $ 1,045,603 | $ 749,294 |
Predecessor | ||||
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||
Beginning present value | $ 392,604 | 1,314,562 | ||
Changes during the year | ||||
Adoption of ASU 2015-02 | (224,965) | |||
Revenues less production | (144,256) | |||
Net changes in prices, production and other costs | (394,173) | |||
Development costs incurred | 69,080 | |||
Net changes in future development costs | 436,041 | |||
Extensions and discoveries | 12,449 | |||
Revisions of previous quantity estimates | (728,254) | |||
Accretion of discount | 91,337 | |||
Net change in income taxes | 402 | |||
Purchases of reserves in-place | 0 | |||
Sales of reserves in-place | (13,314) | |||
Timing differences and other | (26,305) | |||
Net change for the year | (921,958) | |||
Ending present value(2) | $ 392,604 |
Quarterly Financial Results (_3
Quarterly Financial Results (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | |||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | ||||||||
Total revenues | $ 85,145 | $ 97,660 | $ 79,462 | $ 87,128 | $ 93,206 | $ 80,892 | $ 84,851 | $ 98,350 |
(Loss) income from operations | 52,847 | 12,430 | (33,685) | (41,967) | (18,230) | (16,267) | 23,348 | 50,780 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ 54,178 | $ 11,715 | $ (34,074) | $ (40,894) | $ (18,760) | $ (8,485) | $ 23,499 | $ 50,808 |
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders | ||||||||
Basic (in dollars per share) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (0.54) | $ (0.25) | $ 0.69 | $ 1.90 |
Diluted (in dollars per share) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (0.54) | $ (0.25) | $ 0.69 | $ 1.90 |
Loss (gain) on derivative contracts | $ (42,600) | $ 11,300 | $ 30,100 | $ 18,300 | $ 21,900 | $ 11,700 | $ (23,500) | $ (34,200) |
Employee termination benefits | $ 31,600 | $ 4,400 | ||||||
Accelerated vesting of employment compensation | 6,500 | |||||||
Proxy contest | $ 7,200 | |||||||
Terminated merger costs | $ 8,200 |
Uncategorized Items - wfx-20181
Label | Element | Value |
Predecessor [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ (253,124,000) |
Noncontrolling Interest [Member] | Predecessor [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | (510,205,000) |
Retained Earnings [Member] | Predecessor [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ 257,081,000 |