Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Mar. 02, 2018 | Jun. 30, 2017 | |
Document and Entity Information | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Energy XXI Gulf Coast, Inc. | ||
Entity Central Index Key | 1,404,973 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 451,144,204 | ||
Entity Common Stock, Shares Outstanding | 33,268,478 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 151,729 | $ 165,368 |
Accounts receivable, net | ||
Oil and natural gas sales | 55,598 | 69,744 |
Joint interest billings | 6,336 | 6,029 |
Other | 15,726 | 17,944 |
Prepaid expenses and other current assets | 21,602 | 17,980 |
Restricted cash | 6,392 | 32,337 |
Total Current Assets | 257,383 | 309,402 |
Property and Equipment | ||
Oil and natural gas properties, net - full cost method of accounting, including $200.2 million and $376.1 million of unevaluated properties not being amortized at December 31, 2017 and December 31, 2016, respectively | 764,922 | 1,097,471 |
Other property and equipment, net | 10,120 | 20,007 |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 775,042 | 1,117,478 |
Other Assets | ||
Restricted cash | 25,712 | 25,583 |
Other assets | 18,845 | 28,244 |
Total Other Assets | 44,557 | 53,827 |
Total Assets | 1,076,982 | 1,480,707 |
Current Liabilities | ||
Accounts payable | 85,122 | 101,117 |
Accrued liabilities | 45,494 | 55,675 |
Asset retirement obligations | 51,398 | 56,601 |
Derivative financial instruments | 32,567 | |
Current maturities of long-term debt | 21 | 4,268 |
Total Current Liabilities | 214,602 | 217,661 |
Long-term debt, less current maturities | 73,952 | 74,229 |
Asset retirement obligations | 613,453 | 680,507 |
Other liabilities | 10,783 | 12,595 |
Total Liabilities | 912,790 | 984,992 |
Commitments and Contingencies (Note 17) | ||
Stockholders' Equity | ||
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively | 333 | 332 |
Additional paid-in capital | 911,144 | 901,658 |
Accumulated deficit | (747,285) | (406,275) |
Total Stockholders' Equity | 164,192 | 495,715 |
Total Liabilities and Stockholders' Equity | $ 1,076,982 | $ 1,480,707 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Consolidated Balance Sheets | ||
Oil and natural gas properties, net - full cost method of accounting, unevaluated properties not being amortized | $ 200.2 | $ 376.1 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 33,254,963 | 33,211,594 |
Common stock, shares outstanding | 33,254,963 | 33,211,594 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2014 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Revenues | ||||||||||||||||||||
Oil sales | $ 113,697 | $ 118,484 | $ 133,793 | $ 252,277 | $ 365,974 | $ 481,922 | ||||||||||||||
Natural gas liquids sales | 2,209 | 2,370 | 2,227 | 4,597 | 6,806 | 8,542 | ||||||||||||||
Natural gas sales | 12,261 | 13,753 | 18,368 | 32,121 | 44,382 | 53,805 | ||||||||||||||
(Loss) Gain on derivative financial instruments | (12,466) | 9,412 | 3,698 | 13,110 | 644 | (32,625) | ||||||||||||||
Total Revenues | 115,701 | 144,019 | 158,086 | 302,105 | 417,806 | 511,644 | ||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 77,822 | 83,655 | 77,267 | 160,922 | 238,744 | 319,671 | ||||||||||||||
Production taxes | 471 | 482 | 239 | 721 | 1,192 | 1,355 | ||||||||||||||
Gathering and transportation | (2,441) | 2,678 | 11,222 | 13,900 | 11,459 | 21,666 | ||||||||||||||
Pipeline facility fee | 10,495 | 10,494 | 10,494 | 20,988 | 31,483 | 41,977 | ||||||||||||||
Depreciation, depletion and amortization | 36,131 | 38,685 | 41,896 | 80,581 | 116,712 | 150,151 | ||||||||||||||
Accretion of asset retirement obligations | 9,753 | 9,984 | 13,081 | 23,065 | 32,818 | 42,780 | ||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | 40,774 | 40,774 | 40,774 | 185,860 | $ 406,300 | |||||||||||||
General and administrative expense | 15,026 | 20,716 | 23,848 | 42,320 | 57,346 | 72,057 | ||||||||||||||
Reorganization items | 2,244 | 2,244 | 2,555 | |||||||||||||||||
Total Costs and Expenses | 406,275 | 147,257 | 166,694 | 218,821 | 385,515 | 532,772 | 838,072 | |||||||||||||
Operating Loss | (406,275) | (211,462) | (31,556) | (22,675) | (60,735) | (83,410) | (114,966) | (326,428) | ||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 52 | 80 | 22 | 102 | 154 | 254 | ||||||||||||||
Interest expense | (3,653) | (3,642) | (3,834) | (7,476) | (11,129) | (14,836) | ||||||||||||||
Total Other (Expense) Income, net | (3,601) | (3,562) | (3,812) | (7,374) | (10,975) | (14,582) | ||||||||||||||
Loss Before Reorganization Items and Income Taxes | (406,275) | (341,010) | ||||||||||||||||||
(Loss) Income Before Income Taxes | (406,275) | (35,157) | (26,237) | (64,547) | (90,784) | (125,941) | (341,010) | |||||||||||||
Income Tax Benefit | 0 | |||||||||||||||||||
Net (Loss) Income | (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | (341,010) | |||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ (406,275) | $ (341,010) | ||||||||||||||||||
(Loss) Earnings per Share | ||||||||||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 33,212 | 33,239 | ||||||||||||||||||
Diluted (in shares) | 33,212 | 33,239 | ||||||||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | |||||||||||||||
Predecessor | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | 256,050 | $ 532,505 | $ 1,025,017 | |||||||||||||||||
Natural gas liquids sales | 3,533 | 14,852 | 27,714 | |||||||||||||||||
Natural gas sales | 37,103 | 69,255 | 117,282 | |||||||||||||||||
(Loss) Gain on derivative financial instruments | 90,506 | 235,439 | ||||||||||||||||||
Total Revenues | 296,686 | 707,118 | 1,405,452 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 136,578 | 328,183 | 449,972 | |||||||||||||||||
Production taxes | 482 | 1,442 | 8,385 | |||||||||||||||||
Gathering and transportation | 5,910 | 33,156 | 34,707 | |||||||||||||||||
Pipeline facility fee | 20,330 | 40,659 | ||||||||||||||||||
Depreciation, depletion and amortization | 60,202 | 339,539 | 705,521 | |||||||||||||||||
Accretion of asset retirement obligations | 38,380 | 64,708 | 50,081 | |||||||||||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | 77,781 | $ 2,330,500 | 2,814,028 | 2,421,884 | |||||||||||
Goodwill impairment | $ 329,300 | 329,293 | ||||||||||||||||||
General and administrative expense | 27,557 | 102,736 | 116,500 | |||||||||||||||||
Total Costs and Expenses | 367,220 | 3,724,451 | 4,116,343 | |||||||||||||||||
Operating Loss | $ 12,795 | (83,329) | (168,119) | (417,866) | (1,513,148) | (918,200) | (70,534) | (2,431,348) | (3,017,333) | (2,710,891) | ||||||||||
Other Income (Expense) | ||||||||||||||||||||
Loss from equity method investees | (10,746) | (17,165) | ||||||||||||||||||
Other income, net | 117 | 3,596 | 4,176 | |||||||||||||||||
Gain on early extinguishment of debt | 777,000 | 290,300 | 458,300 | 748,600 | 1,525,596 | |||||||||||||||
Interest expense | (12,580) | (405,658) | (323,308) | |||||||||||||||||
Total Other (Expense) Income, net | (12,463) | 1,112,788 | (336,297) | |||||||||||||||||
Loss Before Reorganization Items and Income Taxes | (82,997) | (1,904,545) | (3,047,188) | |||||||||||||||||
Reorganization items | 2,733,608 | (14,201) | ||||||||||||||||||
(Loss) Income Before Income Taxes | 2,650,611 | (1,883,924) | (1,918,746) | (3,047,188) | ||||||||||||||||
Income Tax Benefit | 51 | (87) | (613,350) | |||||||||||||||||
Net (Loss) Income | 2,771,349 | (120,738) | (195,460) | 160,776 | (1,310,583) | (573,392) | 2,650,611 | (1,883,975) | (1,918,659) | (2,433,838) | ||||||||||
Preferred Stock Dividends | 5,664 | 5,194 | 11,468 | |||||||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ 2,771,349 | $ (120,738) | $ (192,612) | $ 158,398 | $ (1,313,393) | $ (576,246) | $ 2,650,611 | $ (1,889,639) | $ (1,923,853) | $ (2,445,306) | ||||||||||
(Loss) Earnings per Share | ||||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ (1.23) | $ (1.97) | $ 1.65 | $ (13.81) | $ (6.08) | $ 26.95 | $ (19.91) | $ (20.08) | $ (25.97) | ||||||||||
Diluted (in dollars per share) | $ 26.45 | $ (1.23) | $ (1.97) | $ 1.55 | $ (13.81) | $ (6.08) | $ 25.30 | $ (19.91) | $ (20.08) | $ (25.97) | ||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 98,337 | 94,926 | 95,822 | 94,167 | ||||||||||||||||
Diluted (in shares) | 104,787 | 94,926 | 95,822 | 94,167 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders’ Equity (Deficit) Predeccesor - USD ($) $ in Thousands | Preferred Stock5.625% Convertible Perpetual Preferred Stock | Common Stock | Paid-in Capital | Accumulated (Deficit) | Total |
Beginning Balance (Predecessor) at Jun. 30, 2014 | $ 1 | $ 468 | $ 1,837,462 | $ (103,371) | $ 1,734,560 |
Beginning Balance (in shares) (Predecessor) at Jun. 30, 2014 | 93,720,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Common stock issued, net of direct costs | Predecessor | $ 4 | 2,332 | 2,336 | ||
Common stock issued (in shares) | Predecessor | 923,000 | ||||
Common stock based compensation | Predecessor | 4,124 | 4,124 | |||
Common stock dividends | Predecessor | (24,436) | (24,436) | |||
Preferred stock dividends | Predecessor | (11,468) | (11,468) | |||
Net (Loss) Income | Predecessor | (2,433,838) | (2,433,838) | |||
Ending Balance (Predecessor) at Jun. 30, 2015 | 1 | $ 472 | 1,843,918 | (2,573,113) | (728,722) |
Ending Balance (in shares) (Predecessor) at Jun. 30, 2015 | 94,643,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Common stock issued, net of direct costs | Predecessor | $ 16 | 430 | 446 | ||
Common stock issued (in shares) | Predecessor | 3,181,000 | ||||
Common stock based compensation | Predecessor | 1,336 | 1,336 | |||
Preferred stock dividends | Predecessor | (5,194) | (5,194) | |||
Revision to prior period financials | Predecessor | 92 | 92 | |||
Net (Loss) Income before revision to prior period financials | Predecessor | (1,918,751) | (1,918,751) | |||
Net (Loss) Income | Predecessor | (1,918,659) | ||||
Ending Balance (Predecessor) at Jun. 30, 2016 | 1 | $ 488 | 1,845,684 | (4,496,966) | (2,650,793) |
Ending Balance (in shares) (Predecessor) at Jun. 30, 2016 | 97,824,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Common stock issued, net of direct costs | Predecessor | $ 16 | (16) | |||
Common stock issued, net of direct costs | $ 332 | 872,230 | 872,562 | ||
Common stock issued (in shares) | Predecessor | 3,146,000 | ||||
Common stock issued (in shares) | 33,212,000 | ||||
Common stock based compensation | Predecessor | 183 | 183 | |||
Revision to prior period financials | Predecessor | (3,292) | (3,292) | |||
Revision to prior period financials | 21,372 | 21,372 | |||
Net (Loss) Income before revision to prior period financials | Predecessor | 2,653,903 | 2,653,903 | |||
Net (Loss) Income | Predecessor | 2,650,611 | ||||
Net (Loss) Income | (406,275) | (406,275) | |||
Cancellation of Predecessor equity | Predecessor | (1) | $ (504) | (1,845,851) | 1,846,355 | (1) |
Ending Balance (Predecessor before cancellation of Predecessor equity) at Dec. 31, 2016 | $ 1 | 504 | 1,845,851 | (1,846,355) | 1 |
Ending Balance at Dec. 31, 2016 | $ 332 | 901,658 | (406,275) | $ 495,715 | |
Ending Balance (in shares) (Predecessor) at Dec. 31, 2016 | 100,970,000 | ||||
Ending Balance (in shares) (Predecessor before cancellation of Predecessor equity) at Dec. 31, 2016 | 100,970,000 | ||||
Ending Balance (in shares) at Dec. 31, 2016 | 33,212,000 | 33,211,594 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Common stock issued, net of direct costs | $ 1 | $ 1 | |||
Common stock issued (in shares) | 43,000 | ||||
Common stock based compensation | 9,486 | 9,486 | |||
Net (Loss) Income | (341,010) | (341,010) | |||
Ending Balance at Dec. 31, 2017 | $ 333 | $ 911,144 | $ (747,285) | $ 164,192 | |
Ending Balance (in shares) at Dec. 31, 2017 | 33,255,000 | 33,254,963 |
Consolidated Statements of Sto6
Consolidated Statements of Stockholders’ Equity (Deficit) Predecessor (Parenthetical) - Predecessor - Preferred Stock | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
5.625% Convertible Perpetual Preferred Stock | ||||
Preferred stock dividend rate (as a percent) | 5.625% | 5.625% | 5.625% | 5.625% |
7.25% Convertible Perpetual Preferred Stock | ||||
Preferred stock dividend rate (as a percent) | 7.25% | 7.25% | 7.25% |
Consolidated Statements of Sto7
Consolidated Statements of Stockholders’ Equity (Deficit) Successor - USD ($) $ in Thousands | Common Stock | Paid-in Capital | Accumulated (Deficit) | Total |
Increase (Decrease) in Stockholders' Equity | ||||
Common stock issued, net of direct costs | $ 332 | $ 872,230 | $ 872,562 | |
Common stock issued (in shares) | 33,212,000 | |||
Successor common stock warrants | 8,056 | 8,056 | ||
Revision to prior period financials | 21,372 | 21,372 | ||
Net (Loss) Income | $ (406,275) | (406,275) | ||
Ending Balance at Dec. 31, 2016 | $ 332 | 901,658 | (406,275) | $ 495,715 |
Ending Balance (in shares) at Dec. 31, 2016 | 33,212,000 | 33,211,594 | ||
Increase (Decrease) in Stockholders' Equity | ||||
Common stock issued, net of direct costs | $ 1 | $ 1 | ||
Common stock issued (in shares) | 43,000 | |||
Common stock based compensation | 9,486 | 9,486 | ||
Net (Loss) Income | (341,010) | (341,010) | ||
Ending Balance at Dec. 31, 2017 | $ 333 | $ 911,144 | $ (747,285) | $ 164,192 |
Ending Balance (in shares) at Dec. 31, 2017 | 33,255,000 | 33,254,963 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows $ in Thousands | 12 Months Ended |
Jun. 30, 2015USD ($) | |
Predecessor | |
Cash Flows From Operating Activities | |
Net (loss) income | $ (2,433,838) |
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities: | |
Depreciation, depletion and amortization | 705,521 |
Impairment of oil and natural gas properties | 2,421,884 |
Goodwill impairment | 329,293 |
Deferred income tax benefit | (614,383) |
Change in fair value of derivative financial instruments | (52,036) |
Accretion of asset retirement obligations | 50,081 |
Loss from equity method investees | 17,165 |
Amortization and write-off of debt issuance costs, payment of interest in kind and other | 23,247 |
Stock-based compensation | 4,124 |
Changes in operating assets and liabilities | |
Accounts receivable | 51,284 |
Prepaid expenses and other assets | 48,062 |
Settlement of asset retirement obligations | (106,573) |
Accounts payable and accrued liabilities | (113,078) |
Net Cash Provided by (Used in) Operating Activities | 330,753 |
Cash Flows from Investing Activities | |
Acquisitions, net of cash | (301) |
Capital expenditures | (723,829) |
Insurance payments received | 3,920 |
Change in equity method investments | 12,642 |
Change in restricted cash | (14,676) |
Proceeds from the sale of properties | 261,931 |
Other | (135) |
Net Cash (Used in) Provided by Investing Activities | (460,448) |
Cash Flows from Financing Activities | |
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,336 |
Dividends to shareholders - common | (24,436) |
Dividends to shareholders - preferred | (11,468) |
Cash restricted under revolving credit facility related to property sold | (21,000) |
Proceeds from long-term debt | 2,586,572 |
Payments on long-term debt | (1,747,849) |
Debt issuance costs | (43,352) |
Other | (66) |
Net Cash (Used in) Provided by Financing Activities | 740,737 |
Net (Decrease) Increase in Cash and Cash Equivalents | 611,042 |
Cash and Cash Equivalents, beginning of period | 145,806 |
Cash and Cash Equivalents, end of period | $ 756,848 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2017 | |
Organization | |
Organization | ENERGY XXI GULF COAST, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 — Organization Nature of Operations Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006. Prior to emergence from the Chapter 11 Cases (as defined below), EGC was an indirect wholly owned operating subsidiary of Energy XXI Ltd (“EXXI Ltd” or the “Predecessor”). We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf (“GoM Shelf”), which is an area in less than 1,000 feet of water. Emergence from Chapter 11 On April 14, 2016, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of EGC, EPL Oil & Gas, Inc. (“EPL”), an indirect wholly-owned subsidiary of EXXI Ltd and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11 (the “Chapter 11 Cases”). On December 13, 2016, the Bankruptcy Court entered the Confirmation Order and on December 30, 2016, the Debtors emerged from bankruptcy. On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Debtors emerged from Chapter 11 Cases. In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC, as the new parent entity. Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), EGC applied fresh start accounting upon the Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate. The Chapter 11 proceedings and related matters are addressed in Note 3, “Chapter 11 Proceedings.” |
Revision of Prior Period Financ
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements | |
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements | Note 2 — Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements Revision of Prior Period Financial Statements During the following periods, we identified prior period pre-tax adjustments affecting the statements of operations: Year ended June 30, 2016. Preferred stock dividends were decreased by $3.2 million to reverse the previously accrued but not declared preferred stock dividend. Six Months Ended December 31, 2016. · Oil sales were increased by $1.0 million to reflect revenue associated with pipeline tariffs. · Impairment of oil and natural gas properties was decreased by $9.0 million, resulting from the reduction of asset retirement obligations and related oil and natural gas property balances of the same amount. As we were in a ceiling test impairment position at September 30, 2016, all adjustments to our asset retirement obligations through September 30, 2016 directly impacted the statement of operations for the six months ended December 31, 2016. · Reorganization items were decreased by $ 14.8 million, which is the net impact of adjustments on fresh-start accounting as of the Convenience Date. At December 31, 2016, the cumulative amount of all statement of operations adjustments for both the year ended June 30, 2016 and six months ended December 31, 2016, was $21.4 million. This amount was offset by reorganization and fresh start accounting adjustments for the Predecessor and was an adjustment to Successor’s opening equity. In evaluating whether the previously issued financial statements were materially misstated, the Company applied the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements . SAB No. 108 states that registrants must quantify the impact of correcting all misstatements, including both the carryover (iron curtain method) and reversing (rollover method) effects of prior-year misstatements on the current-year consolidated financial statements, and evaluate the misstatements measured under each method in light of quantitative and qualitative factors. Under SAB No. 108, prior-year misstatements which, if corrected in the current year would be material to the current year, must be corrected by adjusting prior year financial statements, even though such correction previously was and continues to be immaterial to the prior-year financial statements. Correcting prior-year financial statements for such “immaterial misstatements” does not require previously filed reports to be amended. In accordance with accounting guidance presented in ASC 250-10 (SEC Staff Accounting Bulletin No. 99, Materiality), the Company assessed the materiality of the misstatements and concluded that they were not material to any of the Predecessor Company’s previously issued consolidated financial statements. The correction of immaterial misstatements did not have any impact on previously reported oil and natural gas reserve volumes and where applicable, the corrections have been reflected throughout the accompanying notes to the consolidated financial statements. These adjustments impacted the consolidated balance sheet as of December 31, 2016 as follows (in thousands): Successor As of December 31, 2016 As reported Adjustments As Revised ASSETS Current Assets Cash and cash equivalents $ 165,368 $ — $ 165,368 Accounts receivable, net Oil and natural gas sales 68,143 1,601 69,744 Joint interest billings 5,600 429 6,029 Other 17,944 — 17,944 Prepaid expenses and other current assets 25,957 (7,977) 17,980 Restricted cash 32,337 — 32,337 Total Current Assets 315,349 (5,947) 309,402 Property and Equipment Oil and natural gas properties, net 1,097,479 (8) 1,097,471 Other property and equipment, net 18,807 1,200 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 1,116,286 1,192 1,117,478 Other Assets Restricted cash 25,583 — 25,583 Other assets and debt issuance costs, net of accumulated amortization 28,244 — 28,244 Total Other Assets 53,827 — 53,827 Total Assets $ 1,485,462 $ (4,755) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 101,117 $ — $ 101,117 Accrued liabilities 63,660 (7,985) 55,675 Asset retirement obligations 56,601 — 56,601 Current maturities of long-term debt 4,268 — 4,268 Total Current Liabilities 225,646 (7,985) 217,661 Long-term debt, less current maturities 74,229 — 74,229 Asset retirement obligations 696,763 (16,256) 680,507 Other liabilities 14,481 (1,886) 12,595 Total Liabilities 1,011,119 (26,127) 984,992 Stockholders’ Equity Preferred stock — — — Common stock 332 — 332 Additional paid-in capital 880,286 21,372 901,658 Accumulated deficit (406,275) — (406,275) Total Stockholders’ Equity 474,343 21,372 495,715 Total Liabilities and Stockholders’ Equity $ 1,485,462 $ (4,755) $ 1,480,707 These adjustments impacted the consolidated statement of operations for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Revenues Oil sales $ 255,040 $ 1,010 $ 256,050 Natural gas liquids sales 3,533 — 3,533 Natural gas sales 37,103 — 37,103 Total Revenues 295,676 1,010 296,686 Costs and Expenses Lease operating 137,007 (429) 136,578 Production taxes 482 — 482 Gathering and transportation 5,910 — 5,910 Pipeline facility fee 20,330 — 20,330 Depreciation, depletion and amortization 60,626 (424) 60,202 Accretion of asset retirement obligations 38,973 (593) 38,380 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 General and administrative expense 27,557 — 27,557 Total Costs and Expenses 377,705 (10,485) 367,220 Operating Loss (82,029) 11,495 (70,534) Other Income (Expense) Other income, net 117 — 117 Interest expense (12,580) — (12,580) Total Other Expense, net (12,463) — (12,463) Loss Before Reorganization Items and Income Taxes (94,492) 11,495 (82,997) Reorganization items 2,748,395 (14,787) 2,733,608 Loss Before Income Taxes 2,653,903 (3,292) 2,650,611 Income Tax Expense — — — Net Income $ 2,653,903 $ (3,292) $ 2,650,611 Earnings per Share Basic $ 26.99 $ (0.04) $ 26.95 Diluted $ 25.33 $ (0.03) $ 25.30 Weighted Average Number of Common Shares Outstanding Basic 98,337 98,337 98,337 Diluted 104,787 104,787 104,787 These adjustments impacted the consolidated statement of cash flows for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net income $ 2,653,903 $ (3,292) $ 2,650,611 Adjustments to reconcile net income to net cash used in operating activities: Depreciation, depletion and amortization 60,626 (424) 60,202 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 Accretion of asset retirement obligations 38,973 (593) 38,380 Reorganization items (2,838,963) 14,787 (2,824,176) Amortization and write-off of debt issuance costs, payment of interest in kind and other 5,025 — 5,025 Deferred rent 3,355 — 3,355 Stock-based compensation 183 — 183 Changes in operating assets and liabilities Accounts receivable (16,545) (1,010) (17,555) Prepaid expenses and other assets (7,425) — (7,425) Change in restricted cash (25,157) — (25,157) Settlement of asset retirement obligations (18,852) — (18,852) Accounts payable and accrued liabilities 40,584 (429) 40,155 Net Cash Used in Operating Activities (17,473) — (17,473) Cash Flows from Investing Activities Capital expenditures (20,237) — (20,237) Change in restricted cash 31,748 — 31,748 Other 195 — 195 Net Cash Provided by Investing Activities 11,706 — 11,706 Cash Flows from Financing Activities Payments on long-term debt (32,088) — (32,088) Other (35) — (35) Net Cash Used in Financing Activities (32,123) — (32,123) Net Decrease in Cash and Cash Equivalents (37,890) — (37,890) Cash and Cash Equivalents, beginning of period 203,258 203,258 Cash and Cash Equivalents, end of period $ 165,368 $ $ — $ 165,368 These adjustments impacted the consolidated statement of operations for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 531,914 $ 591 $ 532,505 Natural gas liquids sales 14,852 — 14,852 Natural gas sales 69,255 — 69,255 Gain on derivative financial instruments 90,506 — 90,506 Total Revenues 706,527 591 707,118 Costs and Expenses Lease operating 328,183 — 328,183 Production taxes 1,442 — 1,442 Gathering and transportation 33,156 — 33,156 Pipeline facility fee 40,659 — 40,659 Depreciation, depletion and amortization 339,516 23 339,539 Accretion of asset retirement obligations 64,690 18 64,708 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 General and administrative expense 102,736 — 102,736 Total Costs and Expenses 3,723,952 499 3,724,451 Operating Loss (3,017,425) 92 (3,017,333) Other (Expense) Income Loss from equity method investees (10,746) — (10,746) Other income, net 3,596 — 3,596 Gain on early extinguishment of debt 1,525,596 — 1,525,596 Interest expense (405,658) — (405,658) Total Other Income, net 1,112,788 — 1,112,788 Loss Before Reorganization Items and Income Taxes (1,904,637) 92 (1,904,545) Reorganization items (14,201) — (14,201) Loss Before Income Taxes (1,918,838) 92 (1,918,746) Income Tax Benefit (87) — (87) Net Loss (1,918,751) 92 (1,918,659) Preferred Stock Dividends 8,394 (3,200) 5,194 Net Loss Attributable to Common Stockholders $ (1,927,145) $ 3,292 $ (1,923,853) Loss per Share Basic and Diluted $ (20.11) $ 0.03 $ (20.08) Weighted Average Number of Common Shares Outstanding Basic and Diluted 95,822 95,822 95,822 These adjustments impacted the consolidated statement of cash flows for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net loss $ (1,918,751) $ 92 $ (1,918,659) Adjustments to reconcile net loss to net cash (used in) provided by operating activities: Depreciation, depletion and amortization 339,516 23 339,539 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 Change in fair value of derivative financial instruments 19,163 — 19,163 Accretion of asset retirement obligations 64,690 18 64,708 Loss from equity method investees 10,746 — 10,746 Gain on early extinguishment of debt (1,525,596) — (1,525,596) Amortization and write-off of debt issuance costs, payment of interest in kind and other 138,473 — 138,473 Deferred rent 9,154 — 9,154 Provision for loss on accounts receivable 3,200 — 3,200 Stock-based compensation 1,336 — 1,336 Changes in operating assets and liabilities Accounts receivable 42,742 (591) 42,151 Prepaid expenses and other assets (24,438) — (24,438) Change in restricted cash — — — Settlement of asset retirement obligations (78,273) — (78,273) Accounts payable and accrued liabilities (62,187) — (62,187) Net Cash Used in Operating Activities (166,655) — (166,655) Cash Flows from Investing Activities Acquisitions, net of cash (2,797) — (2,797) Capital expenditures (111,884) — (111,884) Insurance payments received 8,251 — 8,251 Change in restricted cash (22,136) — (22,136) Proceeds from the sale of properties 5,693 — 5,693 Other (40) — (40) Net Cash Used in Investing Activities (122,913) — (122,913) Cash Flows from Financing Activities Proceeds from the issuance of common and preferred stock, net of offering costs 334 — 334 Dividends to shareholders – preferred (5,673) — (5,673) Proceeds from long-term debt 1,121 — 1,121 Payments on long-term debt (227,884) — (227,884) Payment of debt assumed in acquisition (25,187) — (25,187) Fees related to debt extinguishment (3,526) — (3,526) Debt issuance costs (2,163) — (2,163) Other (1,044) — (1,044) Net Cash Used in Financing Activities (264,022) — (264,022) Net Decrease in Cash and Cash Equivalents (553,590) — (553,590) Cash and Cash Equivalents, beginning of period 756,848 756,848 Cash and Cash Equivalents, end of period $ 203,258 $ $ — $ 203,258 Summary of Significant Accounting Policies Principles of Consolidation and Reporting. The accompanying consolidated financial statements on December 31, 2017 include the accounts of EGC and its wholly-owned subsidiaries and for the prior periods, the accompanying consolidated financial statements include the accounts of EXXI Ltd and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Predecessor’s consolidated financial statements for the prior periods include certain reclassifications, including a $ 6.7 million, $ 17.9 million and $1 3.6 million reclassification from lease operating expenses to gathering and transportation expenses and a $ 21.0 million, $40.7 million and $0.0 million reclassification from gathering and transportation expenses to pipeline facility fee expense for the six month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, respectively, to conform to the current presentation. Those reclassifications did not have any impact on the Predecessor’s previously reported consolidated result of operations or cash flows. For periods subsequent to filing the Bankruptcy Petitions until the Emergence Date, we have prepared the Predecessor’s consolidated financial statements in accordance with ASC 852. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Fresh-start Accounting. Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented as of December 31, 2017 and prior periods. Although our accounting policies are the same as that of our Predecessor’s, our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and the differences may be material. Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP 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 dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. The Predecessor’s proved reserves quantities of 86.6 MMBOE as of June 30, 2016 were estimated and compiled by its internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). As of December 31, 2016, proved reserves quantities of 121.9 MMBOE were independently estimated and compiled by our internal reservoir engineers. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017 and we engaged NSAI to provide that report. The first NSAI report was delivered by us on May 23, 2017, and NSAI estimated our proved reserves quantities of 109.4 MMBOE as of March 31, 2017 in accordance with the guidelines established by the SEC. As of December 31, 2017, proved reserves quantities of 88.2 MMBOE were estimated by NSAI. The estimated proved reserve quantities discussed above are unaudited. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material. Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents. As of December 31, 2017, cash and cash equivalents include $25.1 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. Restricted Cash . We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in restricted cash on our consolidated balance sheets. As of December 31, 2017 and 2016, restricted cash includes $6 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, primarily using the specific identification method. As of December 31, 2017, our allowance for doubtful accounts was $ 0.6 million. As of December 31, 2016, no allowance for doubtful accounts was necessary. Oil and Natural Gas Properties . We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless accounting for the sale as a reduction of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4‑10. Estimated future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred. Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 6 – “Goodwill” for more information. Derivative Instruments . We have historically used various derivative instruments including crude oil and natural gas put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are recorded as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. Costs incurred in connection with line-of-credit agreements are presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. Asset Retirement Obligations . Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in abandonment timing, regulatory requirements, technological advances and other factors which may be difficult to predict. Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2017 and 2016. General and Administrative Expense . Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our exploration and development activities for the year ended December 31, 2017, for the six month transition period ended December 31, 2016 and for the years ended June 30, 2016 and 2015 was $ 16.4 million $7.8 million, $17.0 million and $49.2 million, respectively. Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument which equals the market value of the underlying stock on the date of grant and is recognized over the period during which an independent director or employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period. Income Taxes . Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For periods ending up through and including the year ended December 31, 2017 we used the then-current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. As a result of the Tax Cuts and Jobs Act of 2017, we re-measured these temporary differences at the new U.S. Federal corporate income tax rate of 21% at December 31, 2017. This resulted in a decrease to our tax-effected deferred tax assets of $204 million, and a corresponding reduction of our valuation allowance of $ 204 million. There was no net effect on income tax expense or benefit recorded for the year ended December 31, 2017 as a result of the Tax Cuts and Jobs Act of 2017. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through Depreciation, Depletion and Amortization (“DD&A”). However, due to changes contained in the Tax Cuts and Jobs Act of 2017, we are now afforded an annual election for equipment purchases after September 27, 2017 through December 31, 2022 that allows us to immediately claim tax deductions for 100% the cost of this property. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization or expensing of intangible drilling and tangible property costs where management deems appropriate. On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Inte |
Chapter 11 Proceedings
Chapter 11 Proceedings | 12 Months Ended |
Dec. 31, 2017 | |
Chapter 11 Proceedings | |
Chapter 11 Proceedings | Note 3 – Chapter 11 Proceedings On April 14, 2016, EXXI Ltd, EGC, EPL and certain other subsidiaries of EXXI Ltd (together with Energy XXI Ltd, the “Debtors”) (excluding Energy XXI GIGS Services, LLC, which leases a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities on Grand Isle, Louisiana, Energy XXI Insurance Limited through which certain insurance coverage for its operations is obtained by the Company, Energy XXI (US Holdings) Limited, Energy XXI International Limited, Energy XXI Malaysia Limited and Energy XXI M21K, LLC, (together, the “Non-Debtors”)) filed voluntary Bankruptcy Petitions in the Bankruptcy Court seeking relief under the provisions of chapter 11 of Title 11 of the United States Bankruptcy Code. The Debtors’ Chapter 11 Cases were jointly administered under the caption “In re: Energy XXI Ltd, et al., Case No. 16‑31928.” Thereafter until emergence, the Debtors operated their businesses and managed their assets as debtors-in-possession under the jurisdiction of the Bankruptcy Court in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of filing the Bankruptcy Petitions, EXXI Ltd’s common stock was delisted from the Nasdaq Global Select Market (the “NASDAQ”) and on May 19, 2016, its registration under Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) was withdrawn. As a result, EXXI Ltd’s common stock was deemed registered pursuant to Section 12(g) of the Exchange Act pursuant to Exchange Act Rule 12g‑2(b). Concurrently with the filing of the Bankruptcy Petitions, EXXI Ltd filed a petition seeking an order for liquidation of EXXI Ltd in the Bermuda Court. On April 15, 2016, John C. McKenna was appointed as Provisional Liquidator by the Bermuda Court. In light of the Plan and the emergence of EXXI Ltd, the Bermuda Court granted the entry into a winding up order formally placing EXXI Ltd in liquidation and confirming John C. McKenna as Provisional Liquidator. The Bermuda Proceeding was completed on June 29, 2017. During the pendency of the Bermuda Proceeding, EXXI Ltd has adopted a modified reporting program with respect to its reporting obligations under federal securities laws. EXXI Ltd did not file periodic reports while the Bermuda Proceeding was pending, but continued to file current reports on Form 8‑K as required by federal securities laws. On July 15, 2016, the Bankruptcy Court entered the Order (A) Approving the Disclosure Statement and the Form and Manner of Service Related Thereto, (B) Setting Dates for the Objection Deadline and Hearing Relating to Confirmation of the Plan and (C) Granting Related Relief . On July 18, 2016, the Debtors filed the solicitation version of the Debtors’ Third Amended Disclosure Statement (as amended, modified, or supplemented from time to time, the “Disclosure Statement”). On November 21, 2016, the Debtors filed the Second Amended Proposed Joint Chapter 11 Plan of Reorganization and the solicitation version of the Second Supplement to the Disclosure Statement Setting Forth Modifications to the Plan. On November 21, 2016, the Bankruptcy Court entered the Order (A) Approving the Adequacy of the Disclosure Statement Supplement to the Debtors’ Third Amended Disclosure Statement Setting Forth Modifications to the Debtors’ Plan and the Continued Solicitation of the Plan and (B) Granting Related Relief approving updated solicitation and tabulation procedures with respect to the Plan. On December 13, 2016, the Bankruptcy Court entered the Confirmation Order pursuant to the Bankruptcy Code, which approved and confirmed the Plan as modified by the Confirmation Order. On December 30, 2016, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other Reorganized Debtors emerged from Chapter 11 Cases. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC, as the new parent entity (the “Company”). Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. Upon emergence from the Chapter 11 Cases, the Company adopted fresh start accounting in accordance with the provisions set forth in ASC 852, because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Under ASC 852, the Company is considered a new legal entity for accounting purposes. For reporting purposes, the pre-reorganization predecessor reflects the business that was transferred to EGC. The financial statements of the pre-reorganization predecessor are EXXI Ltd’s consolidated financial statements. On January 6, 2017, the Company filed a Current Report on Form 8‑K as the initial report of the Company to the SEC and as notice that the Company is the successor issuer to EXXI Ltd under Rule 12g‑3 under the Exchange Act. As a result, the shares of common stock of the Company, par value $0.01 per share, are deemed to be registered under Section 12(g) of the Exchange Act. The Company is thereby deemed subject to the informational requirements of the Exchange Act, and the rules and regulations promulgated thereunder, and in accordance therewith will file reports and other information with the Commission. On February 7, 2017, the board of directors of the Company (the “Board”) adopted a resolution to change the Company’s fiscal year end from June 30 to December 31. Unless otherwise noted, all references to “years” in this Form 10‑K refer to the twelve-month fiscal year, which, prior to July 1, 2016 ended on June 30, and, beginning after June 30, 2016, ends on December 31. Our common stock began trading on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI” at the opening of business on February 28, 2017. The audited financial statements of the Successor on December 31, 2016 reflected an impairment of our oil and natural gas properties of approximately $406.3 million which was recognized due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference related to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. Plan of Reorganization In accordance with the Plan, the following significant transactions occurred: Prepetition Notes In accordance with the Plan, on the Emergence Date, all outstanding obligations under the following notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled: · 11.0% senior secured second lien notes due March 15, 2020 (the “Second Lien Notes”) issued pursuant to that certain Indenture, dated as of March 12, 2015, among EGC, the guarantors party thereto, and U.S. Bank, N.A., as trustee, and all amendments, supplements or modifications thereto and extensions thereof; · 6.875% senior unsecured notes due March 15, 2024 (the “EGC 6.875 Senior Notes”) issued pursuant to that certain indenture, dated May 27, 2014, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 7.50% senior unsecured notes due December 15, 2021 (the “EGC 7.50% Senior Notes”) issued pursuant to that certain indenture, dated September 26, 2013, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 7.75% senior unsecured notes due June 15, 2019 (the “EGC 7.75% Senior Notes”) issued pursuant to that certain indenture, dated February 25, 2011, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 9.25% senior unsecured notes due December 15, 2017 (the “EGC 9.25% Senior Notes,” and together with the EGC 6.875% Senior Notes, the EGC 7.50% Senior Notes, the EGC 7.75% Senior Notes and the “EGC Unsecured Notes”) issued pursuant to that certain indenture, dated December 17, 2010, among EGC, the guarantors party thereto, and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, and all amendments, supplements or modifications thereto and extensions thereof; · 8.25% senior unsecured notes due February 15, 2018 (the “EPL 8.25% Senior Notes”) issued pursuant to that certain indenture, dated as of February 14, 2011, by and EGC, the guarantors party thereto, and U.S. Bank National Association, as trustee, and all amendments, supplements or modifications thereto and extensions thereof; and · 3.0% senior convertible notes due on December 15, 2018 (the “EXXI 3.0% Senior Convertible Notes”) issued pursuant to that certain indenture dated as of November 22, 2013 among EXXI Ltd and Wilmington Savings Fund Society, FSB, as trustee, and all amendments, supplements or modifications thereto and extensions thereof. Prepetition Revolving Credit Facility and Exit Facility On the Emergence Date, by operation of the Plan, all outstanding obligations under the Second Amended and Restated First Lien Credit Agreement (the “Prepetition Credit Agreement” or the “Prepetition Revolving Credit Facility”) and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled. Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”) with the prior lenders under the Prepetition Revolving Credit Facility. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount under the Prepetition Revolving Credit Facility of approximately $74 million plus accrued default interest, fees and expenses and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility, which provides for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the aggregate commitments under the Exit Revolving Facility were $227.8 million, all of which will be utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of Exxon Mobil Corporation (“ExxonMobil”) to secure certain plugging and abandonment obligations. Equity Interests and Warrant Agreement As a result of the Plan, there were no assets remaining in EXXI Ltd, and, under Bermuda law, shareholders (including preferred shareholders) of EXXI Ltd received no payments, and all of its existing share-based compensation plans were also cancelled. EXXI Ltd was dissolved at the conclusion of the Bermuda Proceeding, and as such, the shareholders no longer have any interest in EXXI Ltd as a matter of Bermuda law. On the Emergence Date, EGC entered into a warrant agreement (the “Warrant Agreement”) with Continental Stock Transfer & Trust Company, as Warrant Agent. Pursuant to the terms of the Plan, EGC issued 2,119,889 warrants to certain prepetition noteholders pursuant to the Plan. On the Emergence Date, the Company issued 100% of its shares of common stock to certain of the Debtors’ creditors pursuant to the Plan. The Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes (the “EGC Unsecured Notes Claims”), (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL 8.25% Senior Notes (the “EPL Unsecured Notes Claims”), (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of the Company’s common stock and warrants (including shares of the Company’s common stock issuable upon the exercise thereof) from the registration requirements of the Securities Act of 1933 (the “Securities Act”) pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. Long Term Incentive Plan As of the Emergence Date, the Company also entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the go-forward compensation for the Reorganized Debtors’ officers, directors, employees and consultants (“Service Providers”). Amendments to Articles of Incorporation or Bylaws. Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Second Amended and Restated Certificate of Incorporation (our “Certificate of Incorporation”) and second amended and restated bylaws became effective on the Emergence Date. Under the Certificate of Incorporation, the total number of all shares of capital stock that the Company is authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share . Liabilities Subject to Compromise Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represented EXXI Ltd’s allowed claims and its best estimate of claims expected to be allowed which were to be resolved as part of the bankruptcy proceedings. See Note 4 – “Fresh Start Accounting” on final determination on liabilities subject to compromise by the Bankruptcy Court. Interest Expense The Debtors discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through December 31, 2016 with approximately $52.8 million, representing interest expense from the Petition Date through June 30, 2016. Executory Contracts Under the Bankruptcy Code, the Debtors have the right to assume, amend and assume, or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages. On November 29, 2016, the Debtors filed the Schedule of Rejected Executory Contracts and Unexpired Leases and the Modifications to Schedule of Assumed Executory Contracts and Unexpired Leases as part of the Plan Supplement [Docket No. 1713]. The assumption and rejection of the Debtors’ executory contracts and unexpired leases, as applicable, occurred on the effective date of the Plan in accordance with the terms of the Plan. Potential Claims The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims were required to file proofs of claim by August 22, 2016 (the “Bar Date”). Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors were investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. As of December 31, 2017, all claims have been settled except for certain Class 11 claims that will be paid at their pro rata share of the approximately $1.5 million General Unsecured Claim Distribution defined in the Plan. |
Fresh Start Accounting
Fresh Start Accounting | 12 Months Ended |
Dec. 31, 2017 | |
Fresh Start Accounting | |
Fresh Start Accounting | Note 4 – Fresh Start Accounting On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Company and the other reorganized Debtors emerged from Chapter 11. In connection with the satisfaction of the conditions to effectiveness as set forth in the Confirmation Order and in the Plan, EXXI Ltd and EGC completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC. Accordingly, EGC succeeded to the entire business and operations previously consolidated for accounting purposes at EXXI Ltd. EGC applied fresh start accounting in accordance with the provisions set forth in ASC 852 on the Convenience Date, because (i) the holders of existing voting shares of EXXI Ltd prior to its emergence received less than 50% of the voting shares of EGC outstanding following its emergence from bankruptcy and (ii) the reorganization value of EXXI Ltd’s assets immediately prior to confirmation of the Plan was less than its post-petition liabilities and allowed claims. Adopting fresh start accounting resulted in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit and we allocated the reorganization value to our individual assets based on their estimated fair values. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the consolidated financial statements on or after the Convenience Date are not comparable with the consolidated financial statements prior to that date. Reorganization Value. Reorganization value represents the fair value of the Company’s total assets prior to the consideration of the liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values. Our reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s interest bearing long term debt and shareholders’ equity. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $600 million to $900 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, we estimated the enterprise value to be approximately $ 815.1 million. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and public comparable company analyses. Valuation of Oil and Gas Properties. Our principal assets are our oil and gas properties, which we account for under the full cost method of accounting as described in Note 2 “–Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements”. With the assistance of valuation experts, we determined the fair value of our oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date. Our internal reservoir engineers developed full cycle production models for all of our developed wells and identified undeveloped drilling locations within our leased acreage. The undeveloped locations were categorized based on varying levels of risk using industry standards. The proved locations were limited to wells expected to be drilled in the Company’s five year plan. The locations were then segregated into geographic areas. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange (“NYMEX”) four year forward prices for West Texas Intermediate (“WTI”) oil and Henry Hub natural gas with inflation adjustments applied to periods beyond four years. These prices were adjusted for typical differentials realized by us for location and product quality adjustments. Transportation cost estimates were based on agreements in place at the Emergence Date. Development and operating costs were based on our recent cost trends adjusted for inflation. Risk factors were determined separately for each geographic area. Based on the geological characteristics of each area appropriate risk factors for each of the reserve categories were applied. We and our valuation experts considered production, geological and mechanical risk to determine the probability factor for each reserve category in each area. The risk adjusted after tax cash flows were discounted at 11.1%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. The after tax cash flow computations included utilization of the Company’s unamortized tax basis in the properties as of the Emergence Date. Plugging and abandonment costs were included in the cash flow projections for undeveloped reserves but were excluded for developed reserves since the fair value of this liability was determined separately and included in the Emergence Date liabilities reported on the December 31, 2016 balance sheet. From this analysis we concluded the fair value of our proved reserves was $1,127.6 million, the value of our probable reserves was $295.3 million and the value of our possible reserves was $80.8 million as of the Convenience Date. The value of probable and possible reserves was classified as unevaluated costs. We also reviewed our undeveloped leasehold acreage and concluded that the fair value of our probable and possible reserves appropriately captured the fair value of our undeveloped leasehold acreage. Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. The following table reconciles the enterprise value to the estimated fair value of the Successor Company’s common stock as of the Convenience Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Less: Fair value of debt (78,497) Fair Value of Successor common stock and warrants 901,990 Less: Fair value of warrants (8,056) Fair Value of Successor common stock $ 893,934 Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a new three-year secured credit facility (the “Exit Facility”). The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors proved reserves and proved developed producing reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Prepetition Revolving Credit Facility of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit. On the Emergence Date, the Company entered into a Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent. On the Emergence Date, pursuant to the terms of the Plan, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. The warrants are exercisable from the date of the Warrant Agreement until December 30, 2021 (the “Expiration Date”). The warrants are initially exercisable for one share of the Company’s common stock per warrant (such rate, as adjusted pursuant to the Warrant Agreement, being the “Warrant Exercise Shares”) at an initial exercise price of $43.66 (the “Exercise Price”). The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock. The fair value of the warrants was $3.80 per warrant. A Black- Scholes pricing model with the following assumptions was used in determining the fair value: The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Add: Other working capital liabilities 156,792 Add: Other long-term liabilities 12,595 Add: Asset retirement obligation 737,108 Reorganization value of Successor assets $ 1,886,982 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 set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized. Consolidated Balance Sheet The adjustments set forth in the following consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”), fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). On the Convenience Date, subsequent to the restructuring adjustments and fair value adjustments, we recorded an impairment of our oil and natural gas properties of approximately $406.3 million, primarily due to pricing differences between the 12‑month average oil and gas prices used in the ceiling test and the forward strip prices used to estimate the fresh start fair value of oil and gas properties of the Company (reflected in the column “Impairment”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions. The following table reflects the reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on our consolidated balance sheet as of December 31, 2016 after making adjustments to correct immaterial misstatements. For a detailed explanation of these adjustments, p lease see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements” ( in thousands ): As of December 31, 2016 Predecessor Reorganization Fresh-Start Successor Impairment Successor ASSETS Current Assets Cash and cash equivalents $ 164,817 $ 551 (1) $ — $ 165,368 $ — $ 165,368 Accounts receivable, net — — Oil and natural gas sales 69,744 — — 69,744 — 69,744 Joint interest billings 6,029 — — 6,029 — 6,029 Other 18,909 (965) (3) — 17,944 — 17,944 Prepaid expenses and other current assets 46,123 (26,260) (2) (1,883) (10) 17,980 — 17,980 Restricted cash 32,888 (551) (1) — 32,337 — 32,337 Total Current Assets 338,510 (27,225) (1,883) 309,402 — 309,402 Property and Equipment Oil and natural gas properties, net 491,521 — 1,012,225 (11) 1,503,746 (406,275) 1,097,471 Other property and equipment, net 15,049 — 4,958 (12) 20,007 — 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 506,570 — 1,017,183 1,523,753 (406,275) 1,117,478 Other Assets Restricted cash 25,583 — — 25,583 — 25,583 Other assets 30,174 — (1,930) (13) 28,244 — 28,244 Total Other Assets 55,757 — (1,930) 53,827 — 53,827 Total Assets $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 67,876 $ 33,241 (3) $ — $ 101,117 $ — $ 101,117 Accrued liabilities 40,517 15,158 (3)(4) — 55,675 — 55,675 Asset retirement obligations 58,537 — (1,936) (14) 56,601 — 56,601 Current maturities of long-term debt 74,046 (69,778) (5) — 4,268 — 4,268 Total Current Liabilities 240,976 (21,379) (1,936) 217,661 — 217,661 Long-term debt, less current maturities — 74,229 (5) — 74,229 — 74,229 Asset retirement obligations 492,931 — 187,576 (14) 680,507 — 680,507 Other liabilities 22,776 2,345 (3) (12,526) (15) 12,595 — 12,595 Total Liabilities Not Subject to Compromise 756,683 55,195 173,114 984,992 — 984,992 Liabilities subject to compromise 2,931,419 (2,931,419) (6) — — — — Total Liabilities 3,688,102 (2,876,224) 173,114 984,992 — 984,992 Stockholders’ Equity (Deficit) Preferred stock (Predecessor) 7.25% Convertible perpetual preferred stock (Predecessor) — — — — — — 5.625% Convertible perpetual preferred stock (Predecessor) — — — — — — Common stock (Predecessor) 504 (504) (7) — — — — Common stock (Successor) — 332 (8) — 332 — 332 Additional paid-in capital (Predecessor) 1,845,851 (1,845,851) (7) — — — — Additional paid-in capital (Successor) — 901,658 (8) — 901,658 — 901,658 Accumulated deficit (4,633,620) 3,793,364 (9) 840,256 (16) — (406,275) (406,275) Total Stockholders’ (Deficit) Equity (2,787,265) 2,848,999 840,256 901,990 (406,275) 495,715 Total Liabilities and Stockholders’ (Deficit) Equity $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 Reorganization Adjustments (1) (2) (3) (4) (5) (6) in thousands ): On December 31, 2016 Predecessor Debt 11.0% Senior Secured Second Lien Notes due 2020 $ 1,450,000 8.25% Senior Notes due 2018 213,677 6.875% Senior Notes due 2024 143,993 3.0% Senior Convertible Notes due 2018 363,018 7.5% Senior Notes due 2021 238,071 7.75% Senior Notes due 2019 101,077 9.25% Senior Notes due 2017 249,452 4.14% Promissory Note due 2017 4,001 Capital lease obligations 450 Total debt 2,763,739 Accounts payable 37,424 Accrued liabilities 130,256 Total liabilities subject to compromise 2,931,419 Fair value of equity and warrants issued per the Plan (901,990) Fair value of reinstated accounts payable and accrued liabilities to be settled in cash (43,509) Cash payment for 3.0% Senior Convertible Notes (2,000) Gain on settlement of liabilities subject to compromise $ 1,983,920 (7) (8) (9) in thousands ): December 31, 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 Cancellation of EXXI Ltd equity 1,846,355 Accrual of success fee (12,651) Payments made of plan support parties (24,260) Net impact to accumulated deficit $ 3,793,364 Fresh Start Adjustments (10) (11) (12) (13) (14) 37.1 million. (15) (16) 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 “Reorganization items” in the consolidated statements of operations. The following table summarizes reorganization items ( in thousands ): Predecessor Six Months Ended Year Ended December 31, June 30, 2016 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 $ — Fresh start adjustments 840,256 — Reorganization legal and professional fees and expenses (90,568) (14,201) Gain (loss) on reorganization items $ 2,733,608 $ (14,201) |
Acquisitions and Dispositions
Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions and Dispositions | |
Acquisitions and Dispositions | Note 5 – Acquisitions and Dispositions Acquisition of interest in M21K On August 11, 2015, pursuant to a stock purchase agreement (the “M21K Purchase Agreement”) between Energy XXI M21K, LLC (“EXXI M21K”), in which EXXI Ltd owned 20% interest, and Energy XXI GOM, LLC, an indirect wholly owned subsidiary of EXXI Ltd, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing (the “M21K Acquisition”). The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which was effective as of August 1, 2015, we had owned a 20% interest in M21K through our investment in EXXI M21K. See Note 8 – “Equity Method Investments.” The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their estimated fair values on August 11, 2015 ( in thousands ): Oil and natural gas properties – evaluated $ 73,910 Oil and natural gas properties – unevaluated 39,278 Asset retirement obligations (66,700) Net working capital * (21,301) Fair value of debt assumed (25,187) Cash paid $ — * Sale of the Grand Isle Gathering System On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (the “GIGS”) to Grand Isle Corridor, LP (“Grand Isle Corridor”), a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. for cash consideration of $245 million, plus the assumption by Grand Isle Corridor of the asset retirement obligations associated with the estimated decommissioning costs for the GIGS. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $248.9 million. Also on June 30, 2015, we entered into a triple-net lease agreement with Grand Isle Corridor pursuant to which we will continue to use and operate the GIGS as further discussed in Note 17 – “Commitments and Contingencies.” Sale of interests in the East Bay field On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration was payable in two installments with $5 million received at closing and the remainder in fiscal year 2016. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss recognized. The net reduction to the full cost pool related to this sale was $68.9 million. Subsequent to June 30, 2015, post-closing adjustments reduced the total cash consideration to $20.3 million and the maximum receivable under the overriding royalty interest to $6.4 million. The final settlement occurred in January 2017. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill | |
Goodwill | Note 6 - Goodwill ASC 350, Intangibles—Goodwill and Other , requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed at least annually during the third quarter. Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. In light of the form of the acquisition of EPL (a purchase of stock), this goodwill had no tax basis when recognized, which resulted in no income tax benefit when impaired. In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using an assumed weighted average cost of capital based on market participant data. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. At June 30, 2016, included in other assets and debt issuance costs, net of accumulated amortization, on our consolidated balance sheets was $0.8 million of goodwill associated with the acquisition of a catering business on August 21, 2015. On the Convenience Date, there was no goodwill after recording the effect of the consummation of the transactions contemplated by the Plan. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property and Equipment | |
Property and Equipment | Note 7 – Property and Equipment Property and equipment consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Oil and gas properties Proved properties $ 1,307,009 $ 1,127,608 Less: accumulated depreciation, depletion, amortization and impairment (742,286) (406,275) Proved properties, net 564,723 721,333 Unevaluated properties 200,199 376,138 Oil and gas properties, net 764,922 1,097,471 Other property and equipment 13,780 20,007 Less: accumulated depreciation (3,660) — Other property and equipment, net 10,120 20,007 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 775,042 $ 1,117,478 See Note 4 – “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. For the year ended December 31, 2017, the costs associated with unevaluated properties decreased by $1 75.9 million, of which $ 121.8 million was transferred to evaluated properties due to the forward price outlook and management intent making certain unevaluated properties uneconomical and the remaining $ 54.1 million was the ratable amortization to the evaluated properties. Under the full cost method of accounting, at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12‑month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net capitalized costs of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively. |
Equity Method Investments
Equity Method Investments | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments | |
Equity Method Investments | Note 8 - Equity Method Investments Prior to the M21K Acquisition on August 11, 2015 discussed previously in Note 4 – “Acquisitions and Dispositions,” we owned a 20% interest in EXXI M21K which was engaged in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K. EGC received a management fee from M21K for providing administrative assistance in carrying out its operations. We also provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K. EXXI M21K was a guarantor of a $100 million first lien credit facility agreement entered into by M21K, which had a $40 million borrowing base and under which $28.0 million in loans and $1.2 million in letters of credit were outstanding as of June 30, 2015. At June 30, 2015, M21K was in default due to a breach of certain covenants under this agreement. On August 11, 2015, we acquired all of the equity interests of M21K and repaid the outstanding balance under the M21K credit facility. See Note 15 – “Related Party Transactions.” We recorded an equity loss of $10.7 million and $17.4 million for the years ended June 30, 2016 and 2015, respectively. The equity loss for the year ended June 30, 2015 includes an other-than-temporary impairment related to our investment in EXXI M21K of $11.8 million. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Long-Term Debt | |
Long-Term Debt | Note 9 – Long-Term Debt Long-term debt consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Exit Facility $ 73,996 $ 73,996 4.14% Promissory Note due 2017 — 4,001 Capital lease obligations 21 500 Total debt 74,017 78,497 Less: debt issue costs 44 — Less: current maturities 21 4,268 Total long-term debt $ 73,952 $ 74,229 Maturities of long-term debt as of December 31, 2017 are as follows (in thousands ) Twelve Months Ending December 31, 2018 $ 21 2019 73,996 2020 — 2021 — 2022 — Thereafter — $ 74,017 Exit Facility Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a secured Exit Facility, which matures on December 30, 2019. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors’ proved developed producing reserves as well as our total proved reserves. The Exit Facility consists of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Second Amended and Restated First Lien Credit Agreement (the “Prepetition Revolving Credit Facility”) of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit. Interest on the outstanding amount of the Exit Term Loan, at the Company’s option, will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly. On the Emergence Date, the aggregate credit capacity under the Exit Revolving Facility was approximately $227.8 million, all of which was utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the GoM. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was then agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor of ExxonMobil would be reduced to $200 million from the existing amount of $225 million and, on March 13, 2017, the letters of credit issued in favor of ExxonMobil were reduced to $200 million. Each existing letter of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit). Following the reduction of $25 million in the letters of credit issued in favor of ExxonMobil, the credit capacity under the Exit Revolving Facility was permanently reduced by 50% of the $25 million reduction in the letters of credit, or $12.5 million. The remaining 50%, or $12.5 million, of such aggregate reduction is available for borrowing, under specific circumstances, as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined at a date elected by the Company, and will be redetermined semi-annually thereafter. Currently, the Company has not elected a date for the initial borrowing base determination. The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in the revolving credit capacity would cause the revolving credit exposure to exceed the revolving credit capacity. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises. The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis. Furthermore, for each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan in an amount equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on the Emergence Date and (ii) the then outstanding principal amount of the Exit Term Loan. Based upon the Company’s current expectations with respect to its capital resources, capital expenditures, results from operations and commodity prices, the Company believes that it is reasonably likely that it will be required to make a mandatory prepayment with respect to each fiscal quarter ending on and after March 31, 2018. In that case, the first such payment of approximately $5.55 million would be required to be paid during the fiscal quarter ending June 30, 2018. Any such mandatory prepayment would not, in and of itself, constitute a default under the Exit Facility. Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility, at the Company’s option, will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after the Emergence Date. Unused credit capacity under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears. The Exit Facility is guaranteed by substantially all of the wholly-owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each Reorganized Debtor guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends. On March 3, 2017, the Company, entered into an amendment to the Exit Facility (the “Amendment”). The Amendment, among other things, included updates necessary to reflect the Company changing its fiscal year end from June 30 to December 31. As a result, the Company must now deliver a December 31 reserve report prepared by a third-party engineer by March 1 of each year (or by May 31 with respect to 2017 only) and a reserve report prepared by the Company’s engineers by September 1 of each year. Further, a second amendment and waiver to the Exit Facility (the “Second Amendment”) was entered into by the Company on April 24, 2017. The Second Amendment amended the requirement of the “as of” date from January 1, 2017 to April 1, 2017, only with respect to the first reserve report prepared by a third-party reservoir engineer. Additionally, the Amendment also revised the calculation of: (i) the net present value of the future net revenues expected to accrue to the proved reserves of the Company and its subsidiaries and (ii) the asset coverage ratio, which are calculated by removing the effects of derivative agreements with any counterparties that are not lenders under the Exit Facility. Furthermore, the requirement for the Company and its subsidiaries to have mortgages covering at least 90% of the total value of their proved reserves was amended to require the mortgages to cover at least 90% of the revised net present value of the proved reserves. As of December 31, 2017, we had approximately $74 million in borrowings and $202. 6 million in letters of credit issued under the Exit Facility. Prepetition Revolving Credit Facility The Prepetition Revolving Credit Facility was entered into by EGC in May 2011. The Prepetition Revolving Credit Facility had a maximum facility amount and borrowing base of $327.2 million, of which such amount $99.4 million was the borrowing base under the sub-facility established for EPL prior to the Chapter 11 Cases. Borrowings under the Prepetition Revolving Credit Facility were limited to a borrowing base based on oil and natural gas reserve values. The scheduled date of maturity of the Prepetition Credit Agreement was April 9, 2018. As a result of the filing of the Bankruptcy Petitions, the highest of the margins applied and default interest was accruing under the facility through an additional 2.00% payment of interest in kind (“PIK”) interest. PIK interest totaling $4.7 million was accrued from the Petition Date through December 31, 2016. Following the modification to the cash collateral order, which was approved by the Bankruptcy Court on October 24, 2016, approximately $30.1 million of restricted cash maintained by EGC related to our Prepetition Credit Agreement was withdrawn on October 25, 2016 and applied to permanently reduce the amount outstanding under its Prepetition Credit Agreement to $69.3 million, thereby resulting in a further reduction to the maximum facility amount and borrowing base to $297.1 million. On the Emergence Date, by operation of the Plan, all outstanding obligations under the Prepetition Revolving Credit Facility and the related collateral agreements were cancelled and the credit agreements governing such obligations were cancelled. Prepetition Senior Notes The Predecessor had issued the following prepetition Senior Notes, which in accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled ( in thousands ): Issue Date Face value Maturity Date 11.0% Senior Secured Second Lien Notes 3/12/2015 1,450,000 3/15/2020 8.25% Senior Notes (1) 6/3/2014 510,000 2/15/2018 6.875% Senior Notes 5/27/2014 650,000 3/15/2024 3.0% Senior Convertible Notes 11/18/2013 400,000 12/15/2018 7.5% Senior Notes 9/26/2013 500,000 12/15/2021 7.75% Senior Notes 2/25/2011 250,000 6/15/2019 9.25% Senior Notes 12/17/2010 750,000 12/15/2017 (1) 8.25% Senior Notes was assumed in the EPL Acquisition. During the year ended June 30, 2016, our Predecessor repurchased certain of its unsecured notes in aggregate principal amounts as follows: $506.0 million of 6.875% Senior Notes due 2024 (the “6.875% Senior Notes”), $261.9 million of 7.5% Senior Notes due 2021(the “7.5% Senior Notes”), $148.9 million of 7.75% Senior Notes due 2019 (the “7.75% Senior Notes”), $296.3 million of 8.25% Senior Notes due 2018 (the “8.25% Senior Notes”) and $500.6 million of 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”). Our Predecessor repurchased these notes in open market transactions at a total cost of approximately $215.9 million, (excluding accrued interest), and we recorded a gain on the repurchases totaling approximately $1,492.4 million, net of associated debt issuance costs and certain other expenses. All of the notes repurchased in February 2016, except for the 8.25% Senior Notes with face value of $266.6 million and 9.25% Senior Notes with face value of $471.1 million which both continue to be held by EGC were cancelled at June 30, 2016 and the remaining EGC and EPL senior notes held by EGC were cancelled on December 19, 2016. In addition, in March 2016 certain bondholders holding $37 million in face value of Predecessor’s 3.0% Senior Convertible Notes requested a conversion of their notes into common stock. Upon conversion, we recorded a gain of approximately $33.2 million after proportionate adjustment to the related debt issue costs, accrued interest and original debt issue discount. As a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, EGC’s pre-petition secured indebtedness under the Prepetition Revolving Credit Facility and Second Lien Notes, Energy XXI Ltd’s pre-petition unsecured indebtedness under the 3.0% Senior Convertible Notes, EGC’s pre-petition unsecured indebtedness under the 6.875% Senior Notes, the 7.5% Senior Notes, the 7.75% Senior Notes and the 9.25% Senior Notes and EPL’s pre-petition unsecured indebtedness under the 8.25% Senior Notes became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of Chapter 11. Accordingly, all of EXXI Ltd’s outstanding indebtedness was classified as current in the consolidated balance sheet and it accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Prepetition Revolving Credit Facility, EXXI Ltd accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. EXXI Ltd continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Convenience Date. However, for all of its other indebtedness, in accordance with ASC 852, Reorganizations , it accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Predecessor consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through the Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016. 4.14% Promissory Note In September 2012, the Predecessor entered into a promissory note of $5.5 million to acquire other property and equipment. In accordance with the Plan, on the Emergence Date, all outstanding obligations under the promissory note were reinstated. Under this note, which was secured by such other property and equipment, we were required to make monthly payments of approximately $52,000 and were to pay one lump-sum payment of $3.3 million at maturity in October 2017. This note carried an interest rate of 4.14% per annum. This note was repaid in full on September 29, 2017. Derivative Instruments Premium Financing We financed premiums on derivative instruments that we purchased with our hedge counterparties. Substantially all of our hedge transactions were with Lenders under the Prepetition Revolving Credit Facility. Derivative instruments premium financing was accounted for as debt and this indebtedness is pari passu with borrowings under the Prepetition Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of December 31, 2016, June 30, 2016 and 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $0, $0 and $10.6 million, respectively. Interest Expense The filing of the Bankruptcy Petitions constituted an event of default with respect to the Predecessor’s existing debt obligations. Accordingly, the Predecessor’s pre-petition secured indebtedness under the Prepetition Revolving Credit Facility, Second Lien Notes and EPL and EGC unsecured notes became immediately due and payable and any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 Cases. In addition, as a result of the covenant violations that existed at March 31, 2016 that were not cured prior to the filing of the Bankruptcy Petitions, all of our outstanding indebtedness was classified as current in the consolidated balance sheet at March 31, 2016, and we accelerated the amortization of the associated debt premium and original issue discount, fully amortizing those amounts as of March 31, 2016. In addition, except for amounts related to the Prepetition Revolving Credit Facility, the Predecessor accelerated the amortization of the remaining debt issuance costs related to its outstanding indebtedness, fully amortizing those costs as of March 31, 2016. The Predecessor continued to accrue interest on the Prepetition Revolving Credit Facility subsequent to the Petition Date until the Emergence Date. However, for all our other indebtedness, in accordance with accounting guidance in ASC 852, Reorganizations, the Predecessor accrued interest only up to the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $176.5 million, representing interest expense from the Petition Date through Emergence Date, of which $123.7 pertained to the six month transition period ended December 31, 2016. Interest expense consisted of the following ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Exit Term Loan $ 4,050 $ — $ — $ — Exit Revolving Facility 10,127 — — — Prepetition Revolving Credit Facility — 11,670 15,703 25,506 11.0% Second Lien Notes due 2020 — — 125,852 48,505 8.25% Senior Notes due 2018 — — 27,899 42,075 6.875% Senior Notes due 2024 — — 18,033 44,701 3.0% Senior Convertible Notes due 2018 — — 9,340 12,000 7.50% Senior Notes due 2021 — — 17,414 37,500 7.75% Senior Notes due 2019 — — 8,200 19,375 9.25% Senior Notes due 2017 — — 44,944 69,375 4.14% Promissory Note due 2017 134 — 130 192 Amortization of debt issue cost - Prepetition Revolving Credit Facility — 725 5,185 12,491 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 — — 6,249 2,358 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 - accelerated — — 44,855 — Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 — — 5,047 1,887 Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 - accelerated — — 36,243 — Amortization of fair value premium – 8.25% Senior Notes due 2018 — — (8,818) (11,108) Amortization of fair value premium – 8.25% Senior Notes due 2018 - accelerated — — (7,961) — Amortization of debt issue cost – 6.875% Senior Notes due 2024 — — 457 1,127 Amortization of debt issue cost – 6.875% Senior Notes due 2024 - accelerated — — 1,946 — Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 — — 8,917 11,232 Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 - accelerated — — 33,370 — Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 — — 1,142 1,439 Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 - accelerated — — 4,271 — Amortization of debt issue cost – 7.50% Senior Notes due 2021 — — 478 1,051 Amortization of debt issue cost – 7.50% Senior Notes due 2021 - accelerated — — 2,822 — Amortization of debt issue cost – 7.75% Senior Notes due 2019 — — 168 388 Amortization of debt issue cost – 7.75% Senior Notes due 2019 - accelerated — — 491 — Amortization of debt issue cost – 9.25% Senior Notes due 2017 — — 1,902 2,358 Amortization of debt issue cost – 9.25% Senior Notes due 2017 - accelerated — — 913 — Derivative instruments financing and other 525 185 466 856 $ 14,836 $ 12,580 $ 405,658 $ 323,308 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligations | |
Asset Retirement Obligations | Note 10 – Asset Retirement Obligations The following table describes the changes in our asset retirement obligations ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, 2017 2016 Beginning of period total $ 737,108 $ 537,637 Liabilities incurred 11,353 13,880 Liabilities settled (55,820) (18,852) Revisions* (70,570) (19,577) Accretion expense 42,780 38,380 End of period total 551,468 Fair value fresh start adjustments 185,640 End of period total 664,851 737,108 Less: End of period, current portion 51,398 56,601 End of period, noncurrent portion $ 613,453 $ 680,507 * , resulting from updated estimates as to when the associated wells would cease to be economic, and the downward revision for the six months ended December 31, 2016 was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity. See Note 4 – “Fresh Start Accounting” for the methodology and assumptions used in arriving at fair value fresh start adjustments on the Convenience Date. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Financial Instruments | |
Derivative Financial Instruments | Note 11 – Derivative Financial Instruments We enter into derivative transactions to reduce exposure to fluctuations in the price of crude oil and natural gas with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We have historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in our derivative portfolio. With a costless collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. In a fixed price swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the swap fixed price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap fixed price. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying consolidated balance sheets. Any gains or losses resulting from changes in fair value of our outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. Most of our crude oil production is sold at Heavy Louisiana Sweet. We have historically included contracts indexed to NYMEX-WTI, ICE Brent futures and Argus-LLS futures in our derivative portfolio to closely align and manage our exposure to the associated price risk. On March 14, 2016, the fourteenth amendment to the Prepetition Revolving Credit Facility became effective and required us to unwind certain derivative transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the Prepetition Revolving Credit Facility, and for such repayments to then result in an automatic and permanent reduction in EXXI Ltd’s borrowing base. Accordingly, on March 15, 2016, EXXI Ltd unwound and monetized all of its outstanding crude oil and natural gas contracts and $50.6 million was applied to reduce amounts outstanding under the Prepetition Revolving Credit Facility. The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of derivative arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements. The Company did not enter into any derivative instruments during the six month transition period ended December 31, 2016, accordingly, there were no outstanding derivative contracts on December 31, 2016. As of December 31, 2017, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59 The fair value of our derivative instruments in our consolidated balance sheets were as follows ( in thousands ) Successor Asset Derivative Instruments Liability Derivative Instruments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ — Current $ — Current $ 32,567 Current $ — Non-Current — Non-Current — Non-Current — Non-Current — Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement — — 32,567 — Derivative financial instruments Current — Current — Current — Current — Non-Current — Non-Current — Non-Current — Non-Current — Total gross amounts offset in Balance Sheets — — — — Net amounts presented in Balance Sheets Current — Current — Current 32,567 Current — Non-Current — Non-Current — Non-Current — Non-Current — $ — $ — $ 32,567 $ — The following table presents information about the components of the gain (loss) on derivative instruments ( in thousands ). Year Ended Six Months December 31, Ended Year Ended June 30, Gain (loss) on derivative financial instruments 2017 2016 2016 2015 Cash Settlements $ (58) $ — $ 59,081 $ 81,049 Proceeds from monetizations — — 50,588 102,354 Change in fair value (32,567) — (19,163) 52,036 Total gain (loss) on derivative financial instruments $ (32,625) $ — $ 90,506 $ 235,439 We monitor the creditworthiness of our counterparties who are also a part of our bank lending group. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. As of December 31, 2017, we had no collateral deposits with our counterparties. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity | |
Stockholders' Equity | Note 12 – Stockholders’ Equity Successor Common and Preferred Stock Amendments to Articles of Incorporation or Bylaws Pursuant to the Plan, on the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Each of the Company’s Certificate of Incorporation and second amended and restated bylaws became effective on the Emergence Date. Under our Certificate of Incorporation, the total number of all shares of capital stock that we are authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share. In order to permit Mr. Reddin to be appointed CEO on an interim basis, the Board adopted the Third Amended and Restated Bylaws (the “Bylaws”) on February 2, 2017. Pursuant to the Bylaws, Section 4.1 was amended to provide that the positions of Chairman of the Board and Chief Executive Officer may be held by the same person only if (i) the two positions are held by the same person solely on an interim basis and (ii) the Board elects a Lead Independent Director for any period in which the two positions are held by the same person. Accordingly, the Bylaws added a new Section 3.8 to establish the position of Lead Independent Director and specified that position’s duties. The Bylaws provide that, during any period in which a Lead Independent Director is serving, the Lead Independent Director may, among other responsibilities, call and preside over all meetings of independent directors and, in the Chairman of the Board’s absence, preside over all meetings of the Company’s stockholders and of the Board. Registration Rights Agreement On the Emergence Date, the Company entered into a registration rights agreement with certain holders representing 10% or more of the Company’s common stock outstanding on that date or who acquire 10% or more of the Company’s common stock outstanding within six months of the Emergence Date (the “Holders”). The Registration Rights Agreement provides resale registration rights for the Holders’ Registerable Securities (as defined in the Registration Rights Agreement). On February 28, 2017, in accordance with the requirements of the Registration Rights Agreement, the Company filed a registration statement on Form S‑3 relating to the resale of an aggregate of 9,272,285 shares of our common stock, which may be offered for sale from time to time by the selling stockholders named in the Form S‑3 prospectus. The number of shares the selling stockholders may sell consists of 9,049,929 shares of common stock that are currently issued and outstanding and 222,356 shares of common stock that they may receive if they exercise their warrants. The selling stockholders acquired all of the shares of common stock and warrants covered by the Form S‑3 prospectus in a distribution pursuant to Section 1145 under the United States Bankruptcy Code in connection with our plan of reorganization that became effective on the Emergence Date. We are not selling any shares of common stock under the Form S‑3 prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The registration statement on Form S‑3 was declared effective by the SEC as of March 23, 2017. On February 28, 2017, pursuant to our satisfaction of all the listing requirements, our common stock began trading on NASDAQ under the symbol “EXXI” at the opening of business. Warrant Agreement On the Emergence Date, the Company issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. The warrants are exercisable from the date of the Warrant Agreement until the Expiration Date. The warrants are initially exercisable for one share of common stock per warrant at an initial exercise price of $43.66. The Warrant Exercise Shares and Exercise Price are subject to customary anti-dilution adjustments. No adjustments to the applicable Exercise Price or Warrant Exercise Shares are required unless the cumulative adjustments required would result in an increase or decrease of at least 1.0% in the applicable Exercise Price or the Warrant Exercise Shares. Additionally, if an adjustment in Exercise Price would reduce the Exercise Price to an amount below par value of the common stock, then such adjustment in Exercise Price will reduce the Exercise Price to the par value of the common stock. Upon the occurrence of certain events prior to the Expiration Date constituting a recapitalization, reorganization, reclassification, consolidation, merger, sale of all or substantially all of the Company’s equity securities or assets or other transaction, in each case which is effected in such a way that the holders of common stock are entitled to receive (either directly or upon subsequent liquidation) cash, stock, securities or other assets or property with respect to or in exchange for common stock (any such event, “Organic Change”), each holder of warrants will be entitled to receive, upon exercise of a Warrant, such cash, stock, securities or other assets or property as would have been issued or payable in such Organic Change (as if the holder had exercised such Warrant immediately prior to such Organic Change) with respect to or in exchange, as applicable, for the number of Warrant Exercise Shares that would have been issued upon exercise of such warrants, if such warrants had been exercised immediately prior to the occurrence of such Organic Change. Holders of warrants are not entitled, by virtue of holding warrants, to vote, to consent, to receive dividends, to consent or to receive notice as stockholders with respect to any meeting of stockholders for the election of the Company’s directors or any other matter, or to exercise any rights whatsoever as the Company’s stockholders unless, until and only to the extent such holders become holders of record of shares of common stock issuable upon exercise of the warrants. The warrants permit a holder of warrants to exercise the warrants for net share or “cashless” settlement in lieu of paying the Exercise Price by authorizing the Company to withhold and not issue to such holder, in payment of the Exercise Price, a number of such Warrant Exercise Shares equal to (i) the number of Warrants Exercise Shares for which the warrants are being exercised, multiplied by (ii) the Exercise Price, and divided by (iii) the Current Sale Price (as defined in the Warrant Agreement) on the Exercise Date. Shares of common stock and warrants issued and outstanding On the Emergence Date, the Company issued (i) 27,897,739 shares of common stock, pro rata, to holders of the claims arising from the Second Lien Notes, (ii) 3,985,391 shares of common stock, pro rata, to holders of the claims arising from the EGC Unsecured Notes Claims, (iii) 1,328,464 shares of common stock, pro rata, to holders of the claims arising from the EPL Unsecured Notes Claims, (iv) 1,271,933 warrants, pro rata, to holders of the EGC Unsecured Notes Claims; and (v) 847,956 warrants, pro rata, to holders of the EPL Unsecured Notes Claims. The Confirmation Order and Plan provide for the exemption of the offer and sale of the shares of common stock and the warrants (including shares of Common Stock issuable upon the exercise thereof) from the registration requirements of the Securities Act pursuant to Section 1145(a)(1) of the Bankruptcy Code. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. As of December 31, 2017, 33,2 54,963 shares of common stock and 2,119,889 warrants were outstanding. Predecessor Common Stock EXXI Ltd’s common stock was traded on the NASDAQ under the symbol “EXXI” prior to its delisting in connection with the commencement of the Chapter 11 proceedings. EXXI Ltd’s common stock resumed trading on the OTC Pink under the symbol “EXXIQ” on April 25, 2016. As a result of filing of the Bankruptcy Petitions, EXXI Ltd’s common stock was suspended from trading on the NASDAQ on April 25, 2016. A Form 25‑NSE was filed with the SEC on May 19, 2016, which removed EXXI Ltd’s securities from listing and registration on NASDAQ. EXXI Ltd’s shareholders were entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. EXXI Ltd had 200,000,000 authorized common shares, par value of $0.005 per share. On April 14, 2016, we received a letter from The NASDAQ Listing Qualifications Staff stating that the Staff has determined that the EXXI Ltd’s securities would be delisted from NASDAQ. The decision was reached by the Staff under NASDAQ Listing Rules 5101, 5110(b) and IM‑5101‑1 as a result of our filing the Bankruptcy Petitions, the associated public interest concerns raised by the Bankruptcy Petitions, concerns regarding the residual equity interest of EXXI Ltd’s listed securities holders and concerns about EXXI Ltd’s ability to sustain compliance with all requirements for continued listing on NASDAQ. On February 24, 2016, EXXI Ltd received a deficiency notice from NASDAQ stating that, based on the closing bid price of its common stock for the prior 30 consecutive business days, EXXI Ltd no longer met the minimum $1.00 per share requirement under NASDAQ Listing Rule 5450(a)(1). Because we did not request an appeal, trading of EXXI Ltd’s common stock was suspended at the opening of business on April 25, 2016, and a Form 25‑NSE was filed with the SEC on May 19, 2016, which removed EXXI Ltd’s securities from listing and registration on NASDAQ. EXXI Ltd’s securities resumed trading on the OTC Markets Group Inc.’s OTC Pink under the symbol “EXXIQ” on April 25, 2016. On December 30, 2016, upon emergence from the Chapter 11 Cases, EXXI Ltd’s common shares were removed from the OTC Market. The Predecessor’s Board adopted a NOL Shareholder Rights Agreement (the “Rights Plan”) designed to preserve substantial tax assets of our U.S. subsidiaries. The Rights Plan is intended to protect our tax benefits and to allow all of our existing shareholders to realize the long-term value of their investment in the Company. As of December 30, 2016, no Rights had been exercised. Predecessor Preferred Stock EXXI Ltd’s bye-laws authorized the issuance of 7,500,000 shares of preferred stock. The Predecessor Board was empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) were to be paid in cash, shares of EXXI Ltd’s common stock, or a combination thereof and were payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year. As a result of filing the Bankruptcy Petitions, EXXI Ltd no longer accrued dividends on preferred stock, accordingly, EXXI Ltd suspended the quarterly dividends on the 5.625% Preferred Stock and the 7.25% Preferred Stock effective January 1, 2016. Preferred stock dividends that would have accrued from the Petition Date through December 31, 2016 totaled approximately $5.7 million. As a result of the Plan, there are no assets remaining in EXXI Ltd, and under Bermuda law, preferred stockholders of EXXI Ltd received no payments. EXXI Ltd was dissolved at the conclusion of the Bermuda Proceeding, and as such, the preferred stockholders no longer have any interest in EXXI Ltd as a matter of Bermuda law. Conversion of Preferred Stock During the six months ended December 31, 2016, we cancelled and converted 300,248 shares of our 5.625% Preferred Stock into a total of 3,145,549 shares of common stock using a conversion rate of 10.4765 common shares per preferred share. During the year ended June 30, 2016, we cancelled and converted 150,787 shares of our 5.625% Preferred Stock into a total of 1,579,522 shares of common stock using a conversion rate of 10.4765 common shares per preferred share. During the year ended June 30, 2015, we cancelled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the year ended June 30, 2015, we also cancelled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information | |
Supplemental Cash Flow Information | Note 13 – Supplemental Cash Flow Information The following table presents our supplemental cash flow information ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Cash paid for interest $ 14,867 $ 7,493 $ 229,569 $ 243,238 Cash paid for income taxes — — 150 933 The following table presents our non-cash investing and financing activities ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Derivative instruments premium financing $ — $ — $ — $ 12,025 Changes in capital expenditures accrued in accounts payable (1,944) 10,242 (37,151) (168,569) Acquisition of property against joint interest billings receivable (1,500) — — Inventory transferred to oil and natural gas properties — — 7,081 — Changes in asset retirement obligations (59,217) (5,697) (2,583) 49,495 Changes in other property and equipment (327) Monetization of derivative instruments applied to Revolving Credit Facility — — 50,588 — |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans | |
Employee Benefit Plans | Note 14 – Employee Benefit Plans Successor Long Term Incentive Plan 2016 Long Term Incentive Plan As of the Emergence Date, the Company entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the compensation for the Company’s officers, directors, employees and consultants (the “Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP is 1,859,552 shares (or 5% of the total new equity). The compensation committee (the “Committee”) of the board of directors of the Company (the “Board”) generally administers the 2016 LTIP and will determine the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP will be awarded to the Service Providers selected in the discretion of the Committee; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated no later than 120 days after the Emergence Date. As of April 29, 2017, the 3% of total new equity had been allocated by the Board. Under the 2016 LTIP, stock options are issued with an exercise price that is not less than the fair market value of our common stock on the date of grant and expire 10 years from the grant date. Stock options that have been granted to date generally vest ratably over a three-year period. The following table sets forth our stock option activity for the year ended December 31, 2017. Weighted Weighted Average Average Remaining Exercise Price Contractual Options Per Share Terms (in years) Outstanding as of December 31, 2016 - $ — — Granted 372,597 28.92 Exercised - - Forfeited (72,448) 28.97 Outstanding as of December 31, 2017 300,149 $ 28.91 9.3 Exercisable on December 31, 2017 — $ — The fair value of the stock options on the date of grant is expensed on a straight-line basis over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. As we do not have sufficient historical stock option exercise experience upon which to base an estimate of expected term, we used the simplified method for estimating expected term . The risk-free interest rate is based on the related United States Treasury yield curve for periods within the expected term of the stock options at the time of the grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. As of December 31, 2017, we had 3 00,149 unvested stock options and $ 1.7 million in unrecognized compensation cost related to unvested stock options. The cost is expected to be recognized over a weighted-average period of 1.3 years. Under the 2016 LTIP, restricted stock units may be granted from time to time as approved by the Committee. To date, the restricted stock units granted by the Committee have a vesting date up to three years from the date of grant and each restricted stock unit represents a right to receive one share of our common stock. The following table sets forth the activity related to restricted stock units for the year ended December 31, 2017. Restricted Average Stock Grant Date Units Fair Value Outstanding as of December 31, 2016 - $ — Granted 775,344 24.22 Vested (68,814) 24.21 Forfeited (93,730) 24.48 Outstanding as of December 31, 2017 612,800 $ 24.19 The fair value of our restricted stock units equals the market value of the underlying common stock on the date of grant . As of December 31, 2017, we had 612,800 unvested restricted stock units and $ 8.5 million in unrecognized compensation cost related to unvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 1.3 years. The following table sets forth stock-based compensation expense ( in thousands ): Successor Year Ended December 31, 2017 Stock Options $ 1,453 Restricted Stock Units 8,033 Total compensation expense recognized $ 9,486 Predecessor Long Term Incentive Plan Prior to the Emergence Date, the Predecessor Company maintained the Energy XXI Services, LLC 2006 Long-Term Incentive Plan (the “2006 Incentive Plan”) an incentive and retention program for its employees. Participation shares (or “Restricted Stock Units”) were issued from time to time at a value equal to its common share price at the time of issue. The Restricted Stock Units generally vested equally over a three-year period. When vesting occurred, the Predecessor Company paid the employee an amount equal to the Predecessor Company’s then current common share price times the number of Restricted Stock Units. The Predecessor Company also awarded performance units (“Performance Units”), including both time-based performance units (“Time-Based Performance Units”) and Total Shareholder Return (“TSR”) Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vested equally over a three-year period. In addition, prior to the Emergence Date, the Predecessor Company maintained the director compensation program which provided for an annual stock award in lieu of cash payment, employee stock purchase plan which allowed employees to purchase its common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period and had granted stock options to its certain officers. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and June 30, 2015, the Predecessor recognized total compensation expense related to restricted stock units and performance based units of $( 0.05) million, $(2,583) million and $3,939 million, respectively. As a result of the Plan, there were no assets remaining in the Predecessor Company, all common shares of the Predecessor Company were cancelled and its shareholders received no payments with respect to the common shares, and the Predecessor Company was dissolved pursuant to Bermuda law at the conclusion of the Bermuda Proceeding. As a result, all awards under the 2006 Incentive Plan that remained unvested, including performance-based awards and all of share-based compensation plans at the Emergence Date were cancelled. Defined Contribution Plans Prior to the Emergence Date, the Predecessor Company’s employees were covered by a discretionary noncontributory profit sharing plan. The plan provided for annual discretionary employer contributions that could vary from year to year. The Predecessor Company also sponsored a qualified 401(k) Plan that provided for matching. Pursuant to the terms of the Plan, on the Emergence Date we assumed the Predecessor Company’s defined contribution plans. The contributions under these plans were as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2017 2016 2016 2015 Profit Sharing Plan $ — $ — $ — $ — $ (768) 401(k) Plan 1,702 — 638 2,852 3,192 Total contributions $ 1,702 $ — $ 638 $ 2,852 $ 2,424 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions | |
Related Party Transactions | Note 15 — Related Party Transactions Successor Related Party Transactions On the Emergence Date, the Company entered into a Registration Rights Agreement with the Holders representing 10% or more of the Common Stock outstanding on that date or who acquire 10% or more of the Common Stock outstanding within six months of the Emergence Date. On the Emergence Date, the Company also entered into the Warrant Agreement with Continental Stock Transfer & Trust Company, as Warrant Agent and issued 2,119,889 warrants to holders of the EGC Unsecured Notes Claims and holders of the EPL Unsecured Notes Claims. For more information see Note 12 – “Stockholders’ Equity.” On February 2, 2017, John D. Schiller, Jr., Bruce W. Busmire and Antonio de Pinho resigned as President and CEO, Chief Financial Officer and Chief Operating Officer, respectively. In connection with Mr. Schiller’s termination of employment, the employment-related provisions of Mr. Schiller’s Executive Employment Agreement, dated as of December 30, 2016 (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller was entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”) continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment was made on April 3, 2017, the 60th day after the termination date. Payments and benefits are subject to Mr. Schiller’s continued compliance with certain confidentiality, non-competition, non-solicitation and non-disparagement provisions of the waiver and release agreement. In addition on February 2, 2017, we entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, we agreed to pay Mr. Schiller a consulting fee of $50,000 per month for up to six months. All amounts due under Schiller Consulting Agreement have been paid as of August 9, 2017. Prior to their departure from the Company, Mr. Busmire and Mr. de Pinho were not party to employment agreements with us, nor did they participate in a severance plan. We paid Mr. Busmire and Mr. de Pinho severance payments on February 15, 2017 in the amount of $750,000 each, less applicable taxes and withholdings, in consideration for the performance of the terms and conditions set forth in their Resignation Agreement and General Release, including, without limitation, a general release and non-disparagement provision. We have also agreed to reimburse Mr. Busmire and Mr. de Pinho for the monthly cost of maintaining health benefits for Mr. Busmire and Mr. de Pinho and their respective spouses and eligible dependents as of the date of their termination for a period of 18 months to the extent Mr. Busmire and Mr. de Pinho elect COBRA continuation coverage. On August 24, 2017, Hugh A. Menown resigned as Executive Vice President, Chief Accounting Officer and Interim Chief Financial Officer. In connection with his separation from the Company, Mr. Menown was entitled to receive the following severance benefits under the Company’s employee severance plan subject to his entry into a waiver and release of claims agreement: (i) a lump-sum cash severance payment in the amount of $580,000, and (ii) to the extent Mr. Menown elects COBRA continuation coverage, medical and dental benefits for him and his spouse for a period of 12 months after termination, subject to the payment of the same monthly premium he was paying at termination, in each case, less any applicable taxes and withholding. The $580,000 cash severance payment was made on September 1, 2017. In addition on August 24, 2017, we entered into a consulting agreement with Mr. Menown, pursuant to which Mr. Menown has agreed to serve as an advisor to the Company during a transition period of up to six months. In consideration for those services, we agreed to pay Mr. Menown a consulting fee of $28,333.33 per month for up to six months. All amounts due to Mr. Menown have been paid as of February 6, 2018. Predecessor Related Party Transactions Prior to the M21K Acquisition on August 11, 2015, we had a 20% interest in EXXI M21K and accounted for this investment using the equity method. We had provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K in the EP Energy property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations of M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligations of M21K estimated at $18.6 million. For these guarantees, M21K agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the years ended June 30, 2016 and 2015, we received $0.3 million and $3.7 million, respectively, related to such guarantees. Prior to the M21K Acquisition, we also received a management fee of $0.98 per BOE produced for providing administrative assistance in carrying out M21K operations. For the years ended June 30, 2016 and 2015, we received management fees of $0.2 million and $3.3 million, respectively. Effective January 15, 2015, the Predecessor Board appointed one of its members, James LaChance, to serve as interim Chief Strategic Officer. In that position, Mr. LaChance pursued discussions with lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by our Chief Executive Officer, in consultation with the Predecessor Board. Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Board of Directors. In light of the significant increase in the amount of time Mr. LaChance was required to spend performing in that new role, EXXI Ltd and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. The consulting agreement expired on July 15, 2015. For years ended June 30, 2016 and 2015, Mr. LaChance earned and was paid consulting fees of $0.1 million and $1.1 million, respectively, under the Consulting Agreement. In accordance with the Consulting Agreement, Mr. LaChance was also entitled to a success fee if he continuously provided consulting services through the closing of one or a series of transactions to provide us and our affiliates with additional capital of more than $1,000 million. The amount of this success fee was capped at $6 million, with up to $5 million payable upon achievement of objective criteria set forth in the Consulting Agreement and up to an additional $1 million payable in the Predecessor Board’s discretion, based on qualitative factors. The success fee was earned and Mr. LaChance received, on March 12, 2015, 1,644,737 RSUs based on a price of $3.04 per share (the value weighted average price of EXXI Ltd’s common stock for the period from December 1, 2014 through January 31, 2015), representing the full $5 million portion of the success fee. With respect to the discretionary portion of the success fee, the Predecessor Board awarded Mr. LaChance the full $1 million amount on October 15, 2015. Fifty percent of this amount was paid in cash in October 2015 and the other fifty percent was paid in the form of 231,482 RSUs, based on a price of $2.16 per share, which was the closing price of EXXI Ltd’s common stock on October 15, 2015. All of the outstanding 1,876,219 RSUs were settled in cash for $1,182,018 on March 12, 2016 based on a price of $0.63 per share. On October 9, 2015, the Predecessor Board determined that the positions of Chief Executive Officer and Chairman of the Board should be held by two different individuals. As a result of that determination, the Predecessor Board elected Mr. LaChance to serve as Chairman of the Board, effective as of October 15, 2015, to serve in such capacity until the earlier of his resignation or removal. Mr. LaChance did not receive any compensation for serving as Chairman of the Board, other than pursuant to director compensation programs that were applicable to other non-employee directors. During the years ended June 30, 2015 and 2014, the Company’s former Chief Executive Officer and President John D. Schiller, Jr. borrowed funds from personal acquaintances or their affiliates, certain of whom provide services to us (“Vendor Loans”). During the year ended December 31, 2017 certain of those lenders provided services to the Company totaling $10.6 million. During the six months ended December 31, 2016 certain of those lenders provided services to the Company totaling $3.3 million. During the years ended June 30, 2016 and 2015, certain of those lenders provided services to the Predecessor Company totaling $35.9 million and $34.7 million, respectively. During 2014, one of the directors on the Predecessor Board made a personal loan to Mr. Schiller at a time prior to becoming a member of the Predecessor Board but while a managing director at Mount Kellett Capital Management LP, which at the time owned a majority interest in Energy XXI M21K and 6.3% of EXXI Ltd’s common stock. From time to time, we have entered into arrangements in the ordinary course of business with entities in which Cornelius Dupré II, who was appointed to the Predecessor Board in October 2010, had an ownership interest. These entities provide us with oil field services. During the year ended December 31, 2017 and during the six month transition period ended December 31, 2016 no payments were made and during fiscal year ended June 30, 2016 and 2015 EXXI Ltd made aggregate payments of approximately $5.6 million and $2.0 million, respectively to these entities for those services. |
Earnings (Loss) per Share
Earnings (Loss) per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings (Loss) per Share | |
Earnings (Loss) per Share | Note 16 — Earnings (Loss) per Share Basic earnings (loss) per share of common stock is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, convertible notes, restricted stock, stock options and other potential common stock equivalents. The following table sets forth the calculation of basic and diluted (loss) earnings per share (“EPS”) ( in thousands, except per share data ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Net (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,659) $ (2,433,838) Preferred stock dividends — — — 5,194 11,468 Net (loss) income attributable to common stockholders $ (341,010) $ (406,275) $ 2,650,611 $ (1,923,853) $ (2,445,306) Weighted average shares outstanding for basic EPS 33,239 33,212 98,337 95,822 94,167 Add dilutive securities — — 6,450 — — Weighted average shares outstanding for diluted EPS 33,239 33,212 104,787 95,822 94,167 (Loss) earnings per share Basic $ (10.26) $ (12.23) $ 26.95 $ (20.08) $ (25.97) Diluted $ (10.26) $ (12.23) $ 25.30 $ (20.08) $ (25.97) The Company’s restricted stock units granted to the members of the Board during the year ended December 31, 2017 are treated as outstanding for basic loss per share calculations since these shares are entitled to participate in dividends declared on common shares, if any, and undistributed earnings. As participating securities, the shares of restricted stock are included in the calculation of basic EPS using the two-class method. For the year ended December 31, 2017, no net loss was allocated to the participating securities. On December 31, 2017, 3,132,729 shares of potential Successor common stock were excluded from the diluted average shares due to an anti-dilutive effect. On December 31, 2016, 2,119,889 shares of potential Successor common stock were excluded from the diluted average shares due to an anti-dilutive effect. For the years ended June 30, 2016 and 2015, 9,439,104 and 8,642,434 shares of potential common stock, respectively, were excluded from the diluted average shares due to an anti-dilutive effect. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies | |
Commitments and Contingencies | Note 17 — Commitments and Contingencies Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. As described below, most of our pending legal proceedings have been stayed by virtue of filing the Bankruptcy Petitions on April 14, 2016. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows. On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose: (i) certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of which provided EXXI Ltd and certain of its subsidiaries with services, (ii) a personal loan made to Mr. Schiller by one of the directors on the Predecessor Board at a time prior to becoming a member of the Predecessor Board, (iii) Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution and (iv) certain perquisites and compensation to Mr. Schiller, including in connection with certain expense reimbursements. The SEC’s claim against EXXI Ltd has been classified as a general unsecured claim to be paid, if at all, its pro rata share of the approximately $1.5 million General Unsecured Claim Distribution defined in the Plan, and, as such, is subject to the Settlement, Release, Injunction, and Related Provisions contained in Article VIII of the Plan, and also is subject to the Confirmation Order. On February 21, 2018, the SEC withdrew its proof of claim. EGC has been cooperating with the SEC in connection with the issues that gave rise to this EXXI Ltd proof of claim, and intends to continue to do so. Lease Commitments. We have non-cancelable operating leases for office space and other assets that expire through December 31, 2018. In addition, on June 30, 2015, we entered into an agreement to assume the operating lease agreement for the Grand Isle Gathering System from our Predecessor as further described below. As of December 31, 2017, future minimum lease commitments under our operating leases are as follows ( in thousands ): Year Ending December 31, Successor 2018 $ 36,035 2019 36,509 2020 43,545 2021 49,598 2022 48,575 Thereafter 152,176 Total $ 366,438 For the year ended December 31, 2017, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, (defined below), was approximately $ 24.1 million. For the six month transition period ended December 31, 2016, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, was approximately $11.9 million. For the years ended June 30, 2016 and 2015, rent expense, including rent incurred on short-term leases but excluding the GIGS Lease, was approximately $6.0 million and $6.4 million, respectively. On June 30, 2015, in connection with the closing of the sale of the Grand Isle Gathering System, Energy XXI GIGS Services, LLC, an indirect wholly-owned subsidiary of the Predecessor Company (the “Tenant”), entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we will continue to operate the Grand Isle Gathering System. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the Grand Isle Gathering System above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum cash monthly payments for the six month transition period ended December 31, 2016 was approximately $17 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes. Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the Grand Isle Gathering System, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain obligations on Grand Isle Corridor, including confidentiality of information and keeping the Grand Isle Gathering System free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the Grand Isle Gathering System. On December 30, 2016, the Tenant, the Company and Grand Isle Corridor entered into an Assignment and Assumption Agreement pursuant to which the Tenant assigned to the Company its right, title, interest, and obligations in and to the purchase and sale agreement relating to the GIGS. Additionally, EGC assumed the obligations of EXXI Ltd as guarantor of Tenant’s obligations under the GIGS Lease pursuant to the Assignment and Assumption of Guaranty and Release Agreement, dated December 30, 2016. Under the GIGS Lease, an event of default would have been triggered by the Tenant upon (i) the filing by either the Tenant or EXXI Ltd of a Bankruptcy Petition or (ii) the failure of either the Tenant, EXXI Ltd or now EGC to make any payment of principal or interest with respect to certain material debt of the Tenant, EXXI Ltd, as the former guarantor, or EGC after giving effect to any applicable cure period or the failure to perform under an agreement or instrument relating to such material debt (collectively, the “Specified Defaults”). Although the Tenant did not file a voluntary petition for reorganization under Chapter 11, the Debtors’ filing of the Bankruptcy Petitions and failure to comply with our material debt instruments, would, among other things, have allowed Grand Isle Corridor to terminate the Lease. As a result, the Tenant and Grand Isle Corridor entered into a waiver to the GIGS Lease, dated as of April 13, 2016, whereby Grand Isle Corridor waived its right to exercise its remedies set forth under the GIGS Lease in the event of the Specified Defaults, except its ability to exercise observer rights as detailed in the GIGS Lease. Letters of Credit and Performance Bonds. As of December 31, 2017, we had approximately $334.1 million of performance bonds outstanding and $200 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico. In April 2015, the Predecessor received letters from the BOEM stating that certain of its subsidiaries no longer qualified for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. Accordingly, as of December 31, 2017, approximately $18 2.4 million of our performance bonds are lease and/or area bonds issued to the BOEM, to which the BOEM has access to ensure our commitment to comply with the terms and conditions of those leases. As of December 31, 2017, we also maintained approximately $15 1.7 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies for wells and facilities pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. As of December 31, 2017, we had $49. 8 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors. To address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April 2015 and thereafter, the Predecessor submitted a long-term financial assurance plan (the “Long-Term Plan”) to the agency. Further, the Predecessor submitted a proposed plan amendment on June 28, 2016 that would revise the executed Long-Term Plan (the “Proposed Plan Amendment”). We continue to work with the BOEM under the Long-Term Plan and the Proposed Plan Amendment. Drilling Rig Commitments. As of December 31, 2017, we have $ 0.6 million committed under a rig contract for recompletions and plugging and abandonment activities with a contract term that ended on January 20, 2018. Subsequent to December 31, 2017, we committed $14 million under two rig contracts with contract terms ranging between two months and six months. Other. We maintain restricted escrow funds as required by certain contractual arrangements. At December 31, 2017, our restricted cash included $25.7 million in cash collateral associated with our bonding requirements, and approximately $6.1 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field that was sold to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC on June 30, 2015 and those funds held in trust will be transferred to the buyers of our interests in that field. We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Taxes | |
Income Taxes | Note 18 — Income Taxes Successor Income Taxes On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the prepetition notes other than the 4.14% promissory note of $5.5 million, the Prepetition Revolving Credit Facility and 100% of the EGC stock owned by Energy XXI USA, Inc., were cancelled. Additionally, new EGC shares and warrants were issued to former creditors as set out in the Plan. Absent an exception, a debtor recognizes Cancellation of Indebtedness Income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (the “Tax Code”) provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the Plan (the “Tax Attribute Reduction Rules”). The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of fresh start accounting, significant historic deferred tax assets and liabilities were reduced, including the liability for accrued outbound 30% withholding tax on the Intercompany Loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan and are not obligations of the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties. The remaining tax bases of our oil and natural gas properties are greater than their respective book carrying values as determined in fresh-start accounting and after reflecting 2017 activity such that we have recorded a deferred tax asset for those properties. These adjustments reflect the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we recorded an after-tax valuation allowance of $168 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. This increase in net tax basis reflects the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. After filing of our initial Form 10-K for the year ended December 31, 2016, tax returns for the Predecessor reflecting the effect of the Tax Attribute Reduction rules were filed resulting in total additional tax basis of $633 million. This amount is made up of an increase in the amount of $663 million related to the change in total CODI excluded (as detailed in the table below), less $30 million related to other changes in estimates of tax attributes resulting from the filings of these tax returns that is unrelated to the Tax Attribute Reduction Rules. These changes were primarily due to: changes in estimate of the amount of the CODI realized and excluded from taxable income and an additional NOL being generated by the Predecessor (including entities not a part of the Successor tax group) that absorbed the CODI exclusion net of other adjustments unrelated to the change in estimate of the CODI exclusion. This change in estimate of the effects of CODI coupled with a decrease in tax return-to-provision adjustment in those tax returns resulted in us increasing our valuation allowance by $224 million (after-tax) in the year ended December 31, 2017. The changes in our tax attributes resulting from the excluded CODI as a result of the tax attribute reduction rules is set out in the following table. Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 Tax Code Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, including as the tax basis in certain assets (net unrealized built-in-losses), against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from the Chapter 11 Cases was considered a change in ownership for purposes of Tax Code Section 382. The limitation under the Tax Code is based on the value of the loss corporation as of the Convenience Date, which reflects value after giving effect to the Plan’s steps. However, this and prior ownership changes and resulting annual limitation will have limited, if any, effect on the Company’s NOLs since all of the NOLs were extinguished by the Tax Attribute Reduction Rules. No cash income taxes were paid during the year ended December 31, 2017, and, based upon current commodity pricing and planned development activity, no cash income taxes have been paid or are expected to be paid or owed for the tax year ending December 31, 2017. We have estimated our effective income tax rate for the year to be zero, as we are forecasting a pre-tax loss at this time. We do not believe that our net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time. A post-Emergence Date pre-tax NOL of approximately $339 million resulting from our post-Emergence Date losses represents our only NOL carryforwards. This post-Emergence Date NOL is not subject to limitation in future usage by the ownership changes rules of Tax Code section 382 or the Tax Attribute Reduction Rules resulting from the Plan, but this NOL cannot be carried back to pre-Emergence Date years to create a cash income tax refund. If, however, the Company were to experience post-Emergence Date changes in stock ownership of greater than 50% within any three-year look back period, this post-Emergence Date NOL would be subject to Tax Code section 382 limitations based upon stock value and other factors at such time. Predecessor Income Taxes The Predecessor Company was a Bermuda company and was generally not subject to income tax in Bermuda. It historically operated through its various subsidiaries in the United States, and, accordingly, U.S. income taxes were provided based upon those U.S. operations and U.S. withholding tax on interest owed to its Bermuda parent on intercompany indebtedness. Pursuant to the Restructuring Support Agreement discussed in Note 3– “Chapter 11 Proceedings” the Predecessor filed bankruptcy and dissolution petitions in the United States and Bermuda, respectively, on the Petition Date. These filings generally had no immediate effect on the Predecessor’s income tax year or income tax reporting requirements. The Predecessor’s Bermuda companies recorded income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalents) accrued on indebtedness of the U.S. companies held by them through the Petition Date. During the year ended June 30, 2016, and for the six-month period ended December 30, 2016, no cash withholding tax payments were made on interest expense or management fees accrued to the Bermuda entities. During fiscal year 2015, changes in expectations regarding future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused management to record a net increase in the valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. Due to continuing losses, management recorded an additional valuation allowance of $650 million resulting in a balance of $1,029.3 million at June 30, 2016. This increase to the valuation allowance against net deferred tax assets due to management’s judgment that the existing U.S. federal NOL carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. Our (loss) income before income taxes attributable to U.S. and non-U.S. operations are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 U.S. (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,913,626) $ (3,050,659) Non-U.S. (loss) income — — — (5,120) 3,471 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) The components of our income tax benefit are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Current U.S. $ — $ — $ — $ — $ 933 Non U.S. — — — — — State — — — (87) 99 Total current — — — (87) 1,032 Deferred U.S. — — — — (564,569) State — — — — (49,813) Total deferred — — — — (614,382) Total income tax benefit $ — $ — $ — $ (87) $ (613,350) The following is a reconciliation of statutory income tax expense to our income tax benefit ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) Statutory rate 35 % 35 % 35 % 35 % 35 % Income tax (benefit) expense computed at statutory rate (119,354) (142,196) 927,714 (671,561) (1,066,516) Reconciling items Federal withholding obligation — — — 8,161 10,331 Nontaxable foreign income — — — 1,791 91 Change in valuation allowance 138,561 142,196 (1,029,335) 650,011 356,798 State income taxes (benefit), net of federal tax benefit — — — (87) (32,314) Non-deductible transaction and restructuring costs 894 — 36,874 — 440 Return to provision adjustments (224,339) — — — — Tax Cuts and Jobs Act of 2017 204,137 — — — — Tax basis in shortfall on partnership dissolution — — — 6,501 — Fresh start adjustments to deferred tax balances: Asset retirement obligation — — 190,715 — — Net operating loss — — 163,027 — — Accrued interest expense — — 115,560 — — Oil and natural gas properties and other property and equipment — — 611,834 — — Deferred state income taxes — — 54,793 — — Withholding taxes — — (81,635) — — Cancellation of stockholders deficit — — (290,665) — — Cancellation of indebtedness income — — (702,972) — — Other fresh start deferred income taxes, net — — 3,284 — — Goodwill impairment — — — — 115,253 Other – Net 101 — 806 5,097 2,567 Income tax benefit $ — $ — $ — $ (87) $ (613,350) For the year ended December 31, 2017, we recorded no income tax expense or benefit. We incurred an additional net operating loss during this period that was reduced by non-deductible restructuring costs, consistent with prior periods. We additionally recognized the return to provision adjustment in CODI from the six-month period ended December 31, 2016 due to the filing of both the year ended June 30, 2016 tax return and the six-month period ended December 30, 2016 tax return. This has no effect on earnings but caused an upward adjustment on our valuation allowance. The most significant difference in the effective tax rate for the Predecessor’s year ended June 30, 2016 that differs from prior year’s activity (apart from changes in the valuation allowance) relates to the non-deductibility of certain bankruptcy restructuring related expenses. Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of deferred taxes are detailed in the table below ( in thousands ): Successor December 31, 2017 2016 Deferred tax assets – non current Oil, natural gas properties and other property and equipment $ 66,297 $ — Asset retirement obligation 139,619 257,988 Tax loss carryforwards on U.S. operations 71,268 — Employee benefit plans 1,698 — Tax partnership activity 676 — Derivative instruments and other 6,839 — Other 19,809 11,120 Total deferred tax assets – non current 306,206 269,108 Deferred tax liabilities Oil, natural gas properties and other property and equipment — (101,463) Total deferred tax liabilities – non current — (101,463) Valuation allowance (306,206) (167,645) Net deferred tax $ — $ — At December 31, 2017, current year activity resulted in an NOL carryover of $3 39 million, which will expire in 2037 if unused. At December 30, 2016, immediately prior to the Emergence Date, the Predecessor had US federal NOL carryforwards of approximately $681 million which were completely eliminated by the Tax Attribution Reduction Rules. We do not have significant state NOL carryforwards from pre-Emergence Date years. Recognizing the late enactment of the Tax Cuts and Jobs Act of 2017 and complexity of accurately accounting for its impact, the SEC in SAB 118 provided guidance that allows registrants to provide a reasonable estimate of the impact of the Tax Cuts and Jobs Act of 2017 in their financial statements and adjust the reported impact in a measurement period not to exceed one year. While we believe we have recorded the predominate effects of the Tax Cuts and Jobs Act of 2017 in provisional accounting the fourth quarter of 2017 (related to the corporate tax rate decrease from 35% to 21%), we continue to assess the impact of the Tax Cuts and Jobs Act of 2017 on our business in order to complete our analysis. Any adjustment to the provisional amounts recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined in the period in which the adjustments are made. Neither the Predecessor nor the Successor has recorded reserves for uncertain tax positions. The Predecessor filed initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2015. The statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On January 12, 2015, the U.S. Internal Revenue Service formally notified management that they had completed their examination of the U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward. |
Concentrations of Credit Risk
Concentrations of Credit Risk | 12 Months Ended |
Dec. 31, 2017 | |
Concentration of Credit Risk | |
Concentrations of Credit Risk | Note 19 — Concentrations of Credit Risk Major Customers . We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. Chevron USA (“Chevron”), Shell Trading Company (“Shell”), Plains Marketing, LP (“Plains”) and Trafigura Trading, LLC (“Trafigura”) accounted for approximately 26%, 25%, 18% and 12%, respectively, of our total oil and natural gas revenues during year ended December 31, 2017. Trafigura, Chevron and Shell accounted for approximately 27%, 26%, and 26%, respectively, of our total oil and natural gas revenues during the six months ended December 31, 2016. Trafigura accounted for approximately 22% of our total oil and natural gas revenues during the year ended June 30, 2016. Chevron accounted for approximately 22% and 24% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. Shell accounted for approximately 21% and 29% of our total oil and natural gas revenues during the years ended June 30, 2016 and 2015, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26% of our total oil and natural gas revenues during the year ended June 30, 2015. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Trafigura, Chevron or Shell curtailed their purchases. Accounts Receivable . Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Derivative Instruments . Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties who are also a part of our bank lending group. We monitor the creditworthiness of our hedge counterparties and during the year ended December 31, 2017, we did not have any event of nonperformance by our counterparties. At December 31, 2016 and June 30, 2016, we had no derivative instruments outstanding. Cash and Cash Equivalents . We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation. Geographic Concentration. Virtually all of our current operations and proved reserves are concentrated in the Gulf of Mexico region. Therefore, we are exposed to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions. We maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed. |
Fair Value
Fair Value | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value | |
Fair Value | Note 20 — Fair Value Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: · Level 1 – quoted prices in active markets for identical assets or liabilities. · Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). · Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and certain notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. The carrying value of the Exit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy. Upon adoption of fresh start accounting, the non-recurring fair value adjustment related to our property and equipment, asset retirement obligation and common stock warrants was $1,007.4 million, $185.6 million and $8.1 million, respectively using Level 3 inputs within the fair value hierarchy. See Note 4 – “Fresh Start Accounting.” Our commodity derivative instruments historically consisted of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimated the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published London Interbank offered rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 11 – “Derivative Financial Instruments.” The fair value of our restricted stock units equals the market value of the underlying common stock on the date of grant . For our stock options, we utilize the Black-Scholes-Merton model to determine fair value, which incorporates various assumptions listed here to value the stock option awards. The dividend yield on our common stock was zero. The expected volatility is based on comparable companies’ asset volatilities. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant. The results of the Monte Carlo simulation model are used for Predecessor’s TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units. During the year ended December 31, 2017, six months ended December 31, 2016 and the year ended June 30, 2016, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Successor Level 2 As of As of December 31, December 31, 2017 2016 Assets: Oil and natural gas derivatives $ — $ — Liabilities: Oil and natural gas derivatives $ 32,567 $ — The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): Successor December 31, 2017 2016 Carrying Value Estimated Carrying Value Estimated Exit Facility $ 73,996 $ 73,996 $ 73,996 $ 73,996 Total $ 73,996 $ 73,996 $ 73,996 $ 73,996 (1) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled. The following table sets forth our Level 3 financial instruments ( in thousands ): Predecessor Six Months Ended Year Ended Year Ended December 31, June 30, June 30, 2016 2016 2015 Liabilities: Performance-based performance units Balance at beginning of period $ — $ 33 $ 6,910 Vested — (775) — Grants charged to general and administrative expense — 760 (6,877) Balance at end of period $ — $ 18 $ 33 |
Prepayments and Accrued Liabili
Prepayments and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Prepayments and Accrued Liabilities | |
Prepayments and Accrued Liabilities | Note 21 — Prepayments and Accrued Liabilities Prepayments and accrued liabilities consist of the following ( in thousands ): Successor December 31, 2017 2016 Prepaid expenses and other current assets Advances to joint interest partners $ 1,381 $ 650 Insurance 5,949 9,600 Inventory 394 470 Royalty deposit 1,021 1,273 Other 12,857 5,987 Total prepaid expenses and other current assets $ 21,602 $ 17,980 Accrued liabilities Advances from joint interest partners 81 374 Employee benefits and payroll 6,791 4,491 Interest payable 185 233 Accrued hedge payable 2,491 — Undistributed oil and gas proceeds 20,079 22,715 Severance taxes payable 558 628 Escrowed reorganization expenses — 25,987 Other 15,309 1,247 Total accrued liabilities $ 45,494 $ 55,675 |
Comparative Period Information
Comparative Period Information | 12 Months Ended |
Dec. 31, 2017 | |
Comparative Period Information | |
Comparative Period Information | Note 22 — Comparative Period Information The following tables present certain transition and comparative period financial information for the six-month period ended December 31, 2016 and 2015, respectively. We made adjustments to correct immaterial misstatements for the six months ended December 31, 2016. For a detailed explanation of these adjustments, see Note 2 — “Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Total Revenues $ 296,686 $ 442,438 Operating loss (70,534) (2,431,348) Income (loss) before income taxes 2,650,611 (1,883,924) Income tax expense (benefit) — 51 Net Income (loss) $ 2,650,611 $ (1,883,975) Preferred stock dividends — 5,664 Net Income (Loss) Attributable to Common Stockholders $ 2,650,611 $ (1,889,639) Earnings (Loss) per Share Basic $ 26.95 $ (19.91) Diluted $ 25.30 $ (19.91) Weighted Average Number of Common Shares Outstanding Basic 98,337 94,926 Diluted 104,787 94,926 Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Net cash used in operating activities $ (17,473) $ (89,924) Net cash provided by (used in) investing activities 11,706 (82,872) Net cash used in financing activities (32,123) (258,162) Net decrease in cash and cash equivalents $ (37,890) $ (430,958) (1) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $ 1.983.9 million, fair value adjustment of $8 40.3 and reorganization expenses of $90.6 million. (1) (2) Included in Operating income (loss) is impairment of oil and natural gas properties of $2,330.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $748.6 million. |
Selected Quarterly Financial Da
Selected Quarterly Financial Data – Unaudited | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Data – Unaudited | |
Selected Quarterly Financial Data – Unaudited | Note 23 — Selected Quarterly Financial Data – Unaudited Unaudited quarterly financial data are as follows ( in thousands, except per share amounts ): Successor Quarter Ended December 31, (2) September 30, June 30, March 31, (3) 2017 2017 2017 2017 Revenues $ 93,838 $ 115,701 $ 144,019 $ 158,086 Operating loss (211,462) (31,556) (22,675) (60,735) Net loss $ (215,069) $ (35,157) $ (26,237) $ (64,547) Net loss per share (1) Basic and Diluted $ (6.47) $ (1.06) $ (0.79) $ (1.94) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income (loss) for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $1 45.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $40.8 million. We made adjustments to correct immaterial misstatements within our previously reported quarterly financial statements. These immaterial misstatements affected certain line items within the cash flow from operations section and did not change the total amount of previously reported cash flows. For a detailed explanation of these adjustments, please see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Quarter Ended December 31, (7) September 30, (6) June 30, (2) March 31, (3) December 31, (4) September 30, (5) 2016 2016 2016 2016 2015 2015 Revenues $ 153,723 $ 142,963 $ 148,395 $ 116,285 $ 184,615 $ 257,823 Operating income (loss) 12,795 (83,329) (168,119) (417,866) (1,513,148) (918,200) Net income (loss) $ 2,771,349 $ (120,738) $ (195,460) $ 160,776 $ (1,310,583) $ (573,392) Preferred stock dividends — — (2,848) 2,378 2,810 2,854 Net income (loss) attributable to common stockholders $ 2,771,349 $ (120,738) $ (192,612) $ 158,398 $ (1,313,393) $ (576,246) Net income (loss) per share attributable to common stockholders (1) Basic $ 28.04 $ (1.23) $ (1.97) $ 1.65 $ (13.81) $ (6.08) Diluted 26.45 (1.23) (1.97) 1.55 (13.81) (6.08) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $143.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $340.5 million and also included in Net loss is gain on early extinguishment of debt of $777.0 million. (4) Included in Operating loss is impairment of oil and natural gas properties of $1,425.8 million and also included in Net loss is gain on early extinguishment of debt of $290.3 million. (5) Included in Operating loss is impairment of oil and natural gas properties of $904.7 million and also included in Net loss is gain on early extinguishment of debt of $458.3 million. (6) Included in Operating loss is impairment of oil and natural gas properties of $77.6 million and also included in Net loss is reorganization expenses of $32.6 million. (7) Included in Net income are gain on settlement of liabilities subject to compromise of $ 1,983.9 million, fair value adjustment gain of $840.3 million and reorganization expenses of $58.0 million. The effect of these adjustments in our consolidated quarterly income statements was as follows: Successor Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 114,991 $ (1,294) $ 113,697 $ 366,792 $ (818) $ 365,974 Natural gas liquids sales 2,209 — 2,209 6,806 — 6,806 Natural gas sales 12,261 — 12,261 44,382 — 44,382 Gain on derivative financial instruments (12,466) — (12,466) 644 — 644 Total Revenues 116,995 (1,294) 115,701 418,624 (818) 417,806 Costs and Expenses Lease operating 77,822 — 77,822 238,315 429 238,744 Production taxes 471 — 471 1,192 — 1,192 Gathering and transportation (2,441) — (2,441) 11,459 — 11,459 Pipeline facility fee 10,495 — 10,495 31,483 — 31,483 Depreciation, depletion and amortization 36,066 65 36,131 116,733 (21) 116,712 Accretion of asset retirement obligations 9,892 (139) 9,753 32,339 479 32,818 Impairment of oil and natural gas properties (2,357) 2,357 — 40,849 (75) 40,774 General and administrative expense 15,026 — 15,026 57,346 — 57,346 Reorganization items — — — (1,529) 3,773 2,244 Total Costs and Expenses 144,974 2,283 147,257 528,187 4,585 532,772 Operating Loss (27,979) (3,577) (31,556) (109,563) (5,403) (114,966) Other Income (Expense) Other income, net 52 — 52 154 — 154 Interest expense (3,653) — (3,653) (11,129) — (11,129) Total Other Expense , net (3,601) — (3,601) (10,975) — (10,975) Loss Before Income Taxes (31,580) (3,577) (35,157) (120,538) (5,403) (125,941) Income Tax Expense — — — — — — Net Loss $ (31,580) $ (3,577) $ (35,157) $ (120,538) $ (5,403) $ (125,941) Loss per Share Basic and Diluted $ (0.95) $ (0.11) $ (1.06) $ (3.63) $ (0.16) $ (3.79) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,241 33,241 33,241 33,236 33,236 33,236 Successor Successor Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 118,180 $ 304 $ 118,484 $ 251,801 $ 476 $ 252,277 Natural gas liquids sales 2,370 — 2,370 4,597 — 4,597 Natural gas sales 13,753 — 13,753 32,121 — 32,121 Gain on derivative financial instruments 9,412 — 9,412 13,110 — 13,110 Total Revenues 143,715 304 144,019 301,629 476 302,105 Costs and Expenses Lease operating 85,336 (1,681) 83,655 160,493 429 160,922 Production taxes 482 — 482 721 — 721 Gathering and transportation 2,678 — 2,678 13,900 — 13,900 Pipeline facility fee 10,494 — 10,494 20,988 — 20,988 Depreciation, depletion and amortization 38,661 24 38,685 80,667 (86) 80,581 Accretion of asset retirement obligations 10,050 (66) 9,984 22,447 618 23,065 Impairment of oil and natural gas properties (848) 848 — 43,206 (2,432) 40,774 General and administrative expense 20,716 — 20,716 42,320 — 42,320 Reorganization items (3,773) 3,773 — (1,529) 3,773 2,244 Total Costs and Expenses 163,796 2,898 166,694 383,213 2,302 385,515 Operating Loss (20,081) (2,594) (22,675) (81,584) (1,826) (83,410) Other Income (Expense) Other income, net 80 — 80 102 — 102 Interest expense (3,642) — (3,642) (7,476) — (7,476) Total Other Expense , net (3,562) — (3,562) (7,374) — (7,374) Loss Before Income Taxes (23,643) (2,594) (26,237) (88,958) (1,826) (90,784) Income Tax Expense — — — — — — Net Loss $ (23,643) $ (2,594) $ (26,237) $ (88,958) $ (1,826) $ (90,784) Loss per Share Basic and Diluted $ (0.71) $ (0.08) $ (0.79) $ (2.68) $ (0.05) $ (2.73) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,237 33,237 33,237 33,234 33,234 33,234 Successor Three Months Ended March 31, 2017 As reported Adjustments As Revised Revenues Oil sales $ 133,621 $ 172 $ 133,793 Natural gas liquids sales 2,227 — 2,227 Natural gas sales 18,368 — 18,368 Gain on derivative financial instruments 3,698 — 3,698 Total Revenues 157,914 172 158,086 Costs and Expenses Lease operating 75,157 2,110 77,267 Production taxes 239 — 239 Gathering and transportation 11,222 — 11,222 Pipeline facility fee 10,494 — 10,494 Depreciation, depletion and amortization 42,006 (110) 41,896 Accretion of asset retirement obligations 12,397 684 13,081 Impairment of oil and natural gas properties 44,054 (3,280) 40,774 General and administrative expense 23,848 — 23,848 Total Costs and Expenses 219,417 (596) 218,821 Operating Loss (61,503) 768 (60,735) Other Income (Expense) Other income, net 22 — 22 Interest expense (3,834) — (3,834) Total Other Expense , net (3,812) — (3,812) Loss Before Income Taxes (65,315) 768 (64,547) Income Tax Expense — — — Net Loss $ (65,315) $ 768 $ (64,547) Loss per Share Basic and Diluted $ (1.97) $ 0.02 $ (1.94) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,228 33,228 33,228 Predecessor Three Months Ended December 31, 2016 As reported Adjustments As Revised Revenues $ 153,065 $ 658 $ 153,723 Operating income 11,708 1,087 12,795 Net income $ 2,785,049 (13,700) $ 2,771,349 Income per Share Basic $ 28.17 $ (0.14) $ 28.04 Diluted $ 26.58 $ (0.13) $ 26.45 Weighted Average Number of Common Shares Outstanding Basic 98,850 98,850 98,850 Diluted 104,787 104,787 104,787 Predecessor Three Months Ended September 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 122,732 $ 352 $ 123,084 Natural gas liquids sales 2,144 — 2,144 Natural gas sales 17,735 — 17,735 Gain on derivative financial instruments — — — Total Revenues 142,611 352 142,963 Costs and Expenses Lease operating 65,170 — 65,170 Production taxes 214 — 214 Gathering and transportation 7,534 — 7,534 Pipeline facility fee 10,165 — 10,165 Depreciation, depletion and amortization 31,573 (432) 31,141 Accretion of asset retirement obligations 19,437 (362) 19,075 Impairment of oil and natural gas properties 86,820 (9,262) 77,558 General and administrative expense 15,435 — 15,435 Total Costs and Expenses 236,348 (10,056) 226,292 Operating Loss (93,737) 10,408 (83,329) Other Income (Expense) Other income, net 62 — 62 Interest expense (4,838) — (4,838) Total Other Expense , net (4,776) — (4,776) Loss Before Reorganization Items and Income Taxes (98,513) 10,408 (88,105) Reorganization items (32,633) — (32,633) Loss Before Income Taxes (131,146) 10,408 (120,738) Income Tax Expense — — — Net Loss $ (131,146) $ 10,408 $ (120,738) Loss per Share Basic and Diluted $ (1.34) $ 0.11 $ (1.23) Weighted Average Number of Common Shares Outstanding Basic and Diluted 97,824 97,824 97,824 |
Supplementary Oil and Gas Infor
Supplementary Oil and Gas Information – Unaudited | 12 Months Ended |
Dec. 31, 2017 | |
Supplementary Oil and Gas Information – Unaudited | |
Supplementary Oil and Gas Information – Unaudited | Note 24 – Supplementary Oil and Gas Information – Unaudited The supplementary data presented reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Property acquisitions Proved $ 96 $ 1,500 $ 26,400 $ — Unevaluated — — — 2,304 Exploration costs 669 — 1,400 38,183 Development costs 62,283 22,300 57,400 608,605 Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. As of December 31, 2017, we have 22 MMBOE in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million. Estimated Net Quantities of Oil and Natural Gas Reserves As of December 31, 2017 the estimates of the net proved oil and natural gas reserves of our oil and natural gas properties located entirely within the U.S. are based on evaluations prepared by NSAI. From June 30, 2013 through June 30, 2016, the Company utilized third-party engineers to audit its internal calculations of reserves and as of December 31, 2016, the reserve quantities were estimated and compiled by its internal reservoir engineers. The Company did not have a fully-engineered third-party report prepared since 2012. Under the terms of its First Lien Exit Credit Agreement executed in 2016, a third party engineer report was required annually, with the first report due by May 31, 2017. As a result, we had a fully-engineered report prepared by NSAI as of March 31, 2017 and the Company plans to have any future annual reserve reports fully-engineered by a third-party engineering firm. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows: Natural Gas Oil Liquids Natural Gas Total (MBbls) (MBbls) (MMcf) (MBOE) Proved reserves at June 30, 2014 (Predecessor) 175,816 9,573 364,856 246,198 Production (14,272) (987) (37,472) (21,504) Extensions, discoveries and other additions 10,056 517 40,330 17,295 Revisions of previous estimates (32,115) (1,615) (75,617) (46,333) Sales of reserves (9,889) (12) (13,554) (12,160) Proved reserves at June 30, 2015 (Predecessor) 129,596 7,476 278,543 183,496 Production (12,624) (923) (33,973) (19,209) Extensions, discoveries and other additions 1,370 46 1,729 1,704 Revisions of previous estimates (61,347) (3,237) (158,681) (91,031) Purchases of reserves 5,145 871 33,529 11,604 Proved reserves at June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 Production (5,482) (167) (13,485) (7,897) Extensions, discoveries and other additions 31,846 375 27,788 36,852 Revisions of previous estimates 6,746 (1,293) 5,788 6,418 Proved reserves at December 31, 2016 (Successor) 95,250 3,148 141,238 121,937 Production (9,324) (288) (17,282) (12,493) Extensions, discoveries and other additions 5,691 217 7,030 7,082 Revisions of previous estimates (17,261) (1,397) (58,001) (28,327) Proved reserves at December 31, 2017 (Successor) 74,356 1,680 72,985 88,199 Proved developed reserves June 30, 2014 (Predecessor) 106,900 5,889 222,916 149,942 June 30, 2015 (Predecessor) 88,607 5,406 187,993 125,345 June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 December 31, 2016 (Successor) 63,728 2,777 113,603 85,439 December 31, 2017 (Successor) 55,005 1,335 58,918 66,160 Proved undeveloped reserves June 30, 2014 (Predecessor) 68,916 3,684 141,940 96,256 June 30, 2015 (Predecessor) 40,989 2,070 90,550 58,151 June 30, 2016 (Predecessor) — — — — December 31, 2016 (Successor) 31,522 371 27,635 36,498 December 31, 2017 (Successor) 19,351 345 14,067 22,039 Our proved reserves decreased by 33.7 MMBOE or by approximately 28% from 121.9 MMBOE at December 31, 2016 to 88.2 MMBOE as of December 31, 2017. The decrease was primarily due to: · 17.4 MMBOE of negative revisions of proved undeveloped reserves. These reserves were written off primarily due to updated technical assessments of undeveloped reserves and, due to delayed drilling activity during 2017 and changes to the Company’s drilling schedule, the SEC’s requirement that undeveloped reserves be developed within five years of the initial booking. · 12.5 MMBOE of production during the period. · 10.7 MMBOE of reserves that became uneconomic due to increased estimates of lease operating expenses. · 9.6 MMBOE of negative revisions of proved developed non-producing reserves. Of these negative revisions, 4.2 MMBOE were primarily due to the revised drilling schedule truncating proved economic field lives and 5.2 MMBOE were due to updated technical assessments. These were offset by: · 7.1 MMBOE of new reserves that were added after technical reviews of the assets. · Upward revisions of 7.0 MMBOE of reserves due to increased product prices and improved field economics. · Upward revisions of 3.3 MMBOE of proved developed producing reserves due to performance. As of December 31, 2017, we have 22 MMBOE in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million. As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. Standardized Measure of Discounted Future Net Cash Flows Future cash inflows as of December 31, 2017 were computed using the following prices: the average oil price prior to quality, transportation fees, and regional price differentials was $47.79 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12‑month period ending on December 31, 2017). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $50.99 per barrel of oil and $26.79 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. For natural gas, the average Henry Hub price used was $2.98 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $2.85 per Mcf after adjusting for energy content, transportation fees, and regional price differentials. The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor As of As of As of December 31, December 31, June 30, 2017 2016 2016 2015 Future cash inflows $ 4,044,208 $ 4,344,985 $ 2,966,317 $ 10,641,151 Less related future Production costs 2,714,819 2,648,363 2,223,645 4,131,526 Development and abandonment costs 1,425,847 1,571,271 1,033,717 1,970,526 Income taxes — — — 168,655 Future net cash flows (96,458) 125,351 (291,045) 4,370,444 Less: Ten percent annual discount for estimated timing of cash flows (111,594) (23,494) (349,398) 1,613,034 Standardized measure of discounted future net cash flows (Predecessor) $ 58,353 $ 2,757,410 Standardized measure of discounted future net cash flows (Successor) $ 15,136 $ 148,845 The increase in our proved reserves had a significant impact on our estimated standardized measure values of the proved reserves which increased from approximately $58.4 million as of June 30, 2016 to approximately $1 48.8 million as of December 31, 2016, mainly due to the following: · The booking of 36.5 MMBOE of proved undeveloped reserves from contingent resource category, and · The increase in proved developed reserves value resulting from greater economic field life due to the booking of proved undeveloped reserves and the delay of significant abandonment costs for all fields. The discounted PV‑10 of the properties as of December 31, 2017, December 31, 2016 and June 30, 2016 are higher than the undiscounted value due to the projected significant plugging and abandonment activity at the end of the life of the properties that are heavily discounted. Changes in Standardized Measure of Discounted Future Net Cash Flows A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Beginning of period (Predecessor) $ 148,845 $ 58,353 $ 2,757,410 $ 5,947,525 Revisions of previous estimates Changes in prices and costs 252,357 (104,993) (3,287,459) (2,959,883) Changes in quantities (198,211) 53,585 (214,631) (2,390,099) Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs 8,908 325,892 26,911 201,234 Purchases (sales) of reserves in place — — 212,961 (244,507) Accretion of discount 14,885 (893) 215,297 760,175 Sales, net of production and gathering and transportation costs (224,976) (131,947) (212,581) (676,949) Net change in income taxes — — 77,025 1,576,954 Changes in rate of production and other (22,862) (2,704) 4,189 (191,668) Development costs incurred 3,878 11,283 10,493 237,173 Changes in estimated future development and abandonment costs 32,312 (59,731) 468,738 497,455 Net change (133,709) 90,492 (2,699,057) (3,190,115) End of period (Predecessor) $ 58,353 $ 2,757,410 End of period (Successor) $ 15,136 $ 148,845 |
Revision of Prior Period Fina33
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements | |
Revision of Prior Period Financial Statements | Revision of Prior Period Financial Statements During the following periods, we identified prior period pre-tax adjustments affecting the statements of operations: Year ended June 30, 2016. Preferred stock dividends were decreased by $3.2 million to reverse the previously accrued but not declared preferred stock dividend. Six Months Ended December 31, 2016. · Oil sales were increased by $1.0 million to reflect revenue associated with pipeline tariffs. · Impairment of oil and natural gas properties was decreased by $9.0 million, resulting from the reduction of asset retirement obligations and related oil and natural gas property balances of the same amount. As we were in a ceiling test impairment position at September 30, 2016, all adjustments to our asset retirement obligations through September 30, 2016 directly impacted the statement of operations for the six months ended December 31, 2016. · Reorganization items were decreased by $ 14.8 million, which is the net impact of adjustments on fresh-start accounting as of the Convenience Date. At December 31, 2016, the cumulative amount of all statement of operations adjustments for both the year ended June 30, 2016 and six months ended December 31, 2016, was $21.4 million. This amount was offset by reorganization and fresh start accounting adjustments for the Predecessor and was an adjustment to Successor’s opening equity. In evaluating whether the previously issued financial statements were materially misstated, the Company applied the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements . SAB No. 108 states that registrants must quantify the impact of correcting all misstatements, including both the carryover (iron curtain method) and reversing (rollover method) effects of prior-year misstatements on the current-year consolidated financial statements, and evaluate the misstatements measured under each method in light of quantitative and qualitative factors. Under SAB No. 108, prior-year misstatements which, if corrected in the current year would be material to the current year, must be corrected by adjusting prior year financial statements, even though such correction previously was and continues to be immaterial to the prior-year financial statements. Correcting prior-year financial statements for such “immaterial misstatements” does not require previously filed reports to be amended. In accordance with accounting guidance presented in ASC 250-10 (SEC Staff Accounting Bulletin No. 99, Materiality), the Company assessed the materiality of the misstatements and concluded that they were not material to any of the Predecessor Company’s previously issued consolidated financial statements. The correction of immaterial misstatements did not have any impact on previously reported oil and natural gas reserve volumes and where applicable, the corrections have been reflected throughout the accompanying notes to the consolidated financial statements. |
Principles of Consolidation and Reporting | Principles of Consolidation and Reporting. The accompanying consolidated financial statements on December 31, 2017 include the accounts of EGC and its wholly-owned subsidiaries and for the prior periods, the accompanying consolidated financial statements include the accounts of EXXI Ltd and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Predecessor’s consolidated financial statements for the prior periods include certain reclassifications, including a $ 6.7 million, $ 17.9 million and $1 3.6 million reclassification from lease operating expenses to gathering and transportation expenses and a $ 21.0 million, $40.7 million and $0.0 million reclassification from gathering and transportation expenses to pipeline facility fee expense for the six month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, respectively, to conform to the current presentation. Those reclassifications did not have any impact on the Predecessor’s previously reported consolidated result of operations or cash flows. For periods subsequent to filing the Bankruptcy Petitions until the Emergence Date, we have prepared the Predecessor’s consolidated financial statements in accordance with ASC 852. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. |
Fresh-start Accounting | Fresh-start Accounting. Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items during the six month transition period ended December 31, 2016. Accordingly, EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented as of December 31, 2017 and prior periods. Although our accounting policies are the same as that of our Predecessor’s, our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and the differences may be material. |
Use of Estimates | Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP 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 dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. The Predecessor’s proved reserves quantities of 86.6 MMBOE as of June 30, 2016 were estimated and compiled by its internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). As of December 31, 2016, proved reserves quantities of 121.9 MMBOE were independently estimated and compiled by our internal reservoir engineers. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017 and we engaged NSAI to provide that report. The first NSAI report was delivered by us on May 23, 2017, and NSAI estimated our proved reserves quantities of 109.4 MMBOE as of March 31, 2017 in accordance with the guidelines established by the SEC. As of December 31, 2017, proved reserves quantities of 88.2 MMBOE were estimated by NSAI. The estimated proved reserve quantities discussed above are unaudited. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material. |
Cash and Cash Equivalents | Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents. As of December 31, 2017, cash and cash equivalents include $25.1 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. |
Restricted Cash | Restricted Cash . We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in restricted cash on our consolidated balance sheets. As of December 31, 2017 and 2016, restricted cash includes $6 million in a money market account. The fair value estimate of money market funds was based on net asset value obtained from quoted prices in active markets and thus represents a Level 1 measurement. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, primarily using the specific identification method. As of December 31, 2017, our allowance for doubtful accounts was $ 0.6 million. As of December 31, 2016, no allowance for doubtful accounts was necessary. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties . We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless accounting for the sale as a reduction of capitalized costs would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties, all of which were recorded as part of fresh start accounting, are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4‑10. Estimated future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict. For the year ended December 31, 2017, we recorded an impairment to oil and natural gas properties of $185.9 million due to the decrease in proved reserves and PV‑10 value. On December 31, 2016, the Company, subsequent to its emergence from bankruptcy, recorded an impairment of its oil and natural gas properties of approximately $406.3 million due to the differences between the fair value of oil and natural gas properties recorded as part of fresh start accounting and the limitation of capitalized costs prescribed under Regulation S-X Rule 4‑10. The most significant difference relates to the use of forward looking oil and natural gas prices in the determination of fair value as opposed to the use of historical first day of the month 12‑month average oil and natural gas prices used in the calculation of limitation on capitalized costs. Reserve adjustment factors as well as the weighted average cost of capital also impacted the determination of the fair value of oil and natural gas properties recorded in fresh start accounting. For the six-month period ended December 31, 2016 and for the years ended June 30, 2016 and 2015, the Predecessor recorded an impairment to its oil and natural gas properties of $77.8 million, $2,814.0 million and $2,421.9 million, respectively. Following emergence from bankruptcy and in accordance with fresh start accounting, the Company, based on the renewed ability to fund development drilling, recorded proved undeveloped reserves of 36.5 MMBOE (unaudited) at December 31, 2016. Future development costs associated with our proved undeveloped reserves at December 31, 2016 totaled approximately $443.2 million (unaudited). As of December 31, 2017, we have 22 MMBOE (unaudited) in proved undeveloped reserves. Future development costs associated with our proved undeveloped reserves at December 31, 2017 totaled approximately $356.1 million (unaudited). As scheduled in our long range plan, all of our proved undeveloped locations are expected to be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report. |
Depreciation, Depletion and Amortization | Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. |
Other Property and Equipment | Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred. |
Goodwill | Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 6 – “Goodwill” for more information. |
Derivative Instruments | Derivative Instruments . We have historically used various derivative instruments including crude oil and natural gas put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are recorded as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. |
Debt Issuance Costs | Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability and are amortized to interest expense generally over the scheduled maturity of the debt utilizing the interest method. Costs incurred in connection with line-of-credit agreements are presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. |
Asset Retirement Obligations | Asset Retirement Obligations . Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in abandonment timing, regulatory requirements, technological advances and other factors which may be difficult to predict. |
Revenue Recognition | Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2017 and 2016. |
General and Administrative Expense | General and Administrative Expense . Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our exploration and development activities for the year ended December 31, 2017, for the six month transition period ended December 31, 2016 and for the years ended June 30, 2016 and 2015 was $ 16.4 million $7.8 million, $17.0 million and $49.2 million, respectively. |
Share-Based Compensation | Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument which equals the market value of the underlying stock on the date of grant and is recognized over the period during which an independent director or employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period. |
Income Taxes | Income Taxes . Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For periods ending up through and including the year ended December 31, 2017 we used the then-current U.S. Federal statutory rate of 35% for measuring these deferred tax assets and liabilities, as adjusted for any applicable state taxes. As a result of the Tax Cuts and Jobs Act of 2017, we re-measured these temporary differences at the new U.S. Federal corporate income tax rate of 21% at December 31, 2017. This resulted in a decrease to our tax-effected deferred tax assets of $204 million, and a corresponding reduction of our valuation allowance of $ 204 million. There was no net effect on income tax expense or benefit recorded for the year ended December 31, 2017 as a result of the Tax Cuts and Jobs Act of 2017. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through Depreciation, Depletion and Amortization (“DD&A”). However, due to changes contained in the Tax Cuts and Jobs Act of 2017, we are now afforded an annual election for equipment purchases after September 27, 2017 through December 31, 2022 that allows us to immediately claim tax deductions for 100% the cost of this property. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Tax Code that allow capitalization or expensing of intangible drilling and tangible property costs where management deems appropriate. On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the prepetition notes other than the 4.14% promissory note of $5.5 million, the Prepetition Revolving Credit Facility and 100% of the EGC stock owned by Energy XXI USA, Inc., were cancelled. Additionally, new EGC shares and warrants were issued to former creditors as set out in the Plan. Absent an exception, a debtor recognizes Cancellation of Indebtedness Income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (the “Tax Code”) provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the Plan (the “Tax Attribute Reduction Rules”). The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of fresh start accounting, significant historic deferred tax assets and liabilities were reduced, including the liability for accrued outbound 30% withholding tax on the Intercompany Loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan and are not obligations of the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties. The remaining tax bases of our oil and natural gas properties are greater than their respective book carrying values as determined in fresh-start accounting and after reflecting 2017 activity such that we have recorded a deferred tax asset for those properties. These adjustments reflect the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we recorded an after-tax valuation allowance of $168 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. This increase in net tax basis reflects the change in estimate from prior filings resulting from recently filed pre-emergence income tax returns for the Predecessor. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable. After filing of our initial Form 10-K for the year ended December 31, 2016, tax returns for the Predecessor reflecting the effect of the Tax Attribute Reduction rules were filed resulting in total additional tax basis of $633 million. This amount is made up of an increase in the amount of $663 million related to the change in total CODI excluded (as detailed in the table below), less $30 million related to other changes in estimates of tax attributes resulting from the filings of these tax returns that is unrelated to the Tax Attribute Reduction Rules. These changes were primarily due to: changes in estimate of the amount of the CODI realized and excluded from taxable income and an additional NOL being generated by the Predecessor (including entities not a part of the Successor tax group) that absorbed the CODI exclusion net of other adjustments unrelated to the change in estimate of the CODI exclusion. This change in estimate of the effects of CODI coupled with a decrease in tax return-to-provision adjustment in those tax returns resulted in us increasing our valuation allowance by $224 million (after-tax) in the year ended December 31, 2017. The changes in our tax attributes resulting from the excluded CODI as a result of the tax attribute reduction rules is set out in the following table. Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax asset, NOL and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized or adjusted in our consolidated financial statements. We have not recorded any reserves for uncertain income tax positions. Recognizing the late enactment of the Tax Cuts and Jobs Act of 2017 and complexity of accurately accounting for its impact, the SEC in SAB 118 provided guidance that allows registrants to provide a reasonable estimate of the impact of the Tax Cuts and Jobs Act of 2017 in their financial statements and adjust the reported impact in a measurement period not to exceed one year. While we believe we have recorded the predominate effects of the Tax Cuts and Jobs Act of 2017 in our provisional accounting the fourth quarter of 2017 (related to the corporate tax rate decrease from 35% to 21%), we continue to assess the impact of the Tax Cuts and Jobs Act of 2017 on our business in order to complete our analysis. Any adjustment to our provisional amounts recorded during the year ended December 31, 2017 will be reported in the reporting period in which any such adjustments are determined in the period in which the adjustments are made. See Note 18 “Income Taxes” for more information. |
Earnings per Share | Earnings per Share . Basic earnings (loss) per share (“EPS”) amounts have been calculated based on the weighted average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution using the treasury stock method. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of the assumed conversion of our Predecessor convertible preferred stock and other potential shares of common stock. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”), as a new Accounting Standards Codification (ASC) Topic, ASC 606. ASU 2014‑09 is effective for us beginning in the first quarter of 2018. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the “entitlements” method of revenue recognition used by EGC. Based on our assessment of revenue contracts with customers against the requirements of the standard, we have not identified any changes to the timing of revenue recognition based on the requirements of ASC 606 that would have a material impact on our consolidated financial statements. We adopted the new standard effective January 1, 2018 utilizing the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption is not material. In February 2016, the FASB issued ASU No. 2016‑02, Leases ( “ ASU 2016‑02”), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB Accounting Standards Codification and created Topic 842, Leases . The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In the normal course of business, we enter into lease agreements to support our operations. We are in the initial stages of evaluating the provisions of ASU 2016‑02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In March 2016, the FASB issued ASU No. 2016‑09 (“ASU 2016‑09”), Compensation - Stock Compensation , to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016‑09 was effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Our adoption of ASU 2016‑09 on January 1, 2017 had no effect on our consolidated financial position, results of operations or cash flows. In June 2016, the FASB issued ASU No. 2016‑13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016‑13”). ASU 2016‑13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows. In August 2016, the FASB issued ASU No. 2016‑15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016‑15”). ASU 2016‑15 provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. We do not expect the adoption of ASU 2016‑15 will have a material impact on our consolidated statement of cash flows and related disclosures other than presentation. In November 2016, the FASB issued ASU No. 2016‑18 , Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016‑18). ASU 2016‑18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. The Company will adopt this update retrospectively effective January 1, 2018. We do not expect the adoption of ASU 2016‑18 will have a material impact on our statement of cash flows and related disclosures other than presentation. |
Revision of Prior Period Fina34
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements | |
Schedule of quantifying prior year misstatements corrected in current year financial statements | These adjustments impacted the consolidated balance sheet as of December 31, 2016 as follows (in thousands): Successor As of December 31, 2016 As reported Adjustments As Revised ASSETS Current Assets Cash and cash equivalents $ 165,368 $ — $ 165,368 Accounts receivable, net Oil and natural gas sales 68,143 1,601 69,744 Joint interest billings 5,600 429 6,029 Other 17,944 — 17,944 Prepaid expenses and other current assets 25,957 (7,977) 17,980 Restricted cash 32,337 — 32,337 Total Current Assets 315,349 (5,947) 309,402 Property and Equipment Oil and natural gas properties, net 1,097,479 (8) 1,097,471 Other property and equipment, net 18,807 1,200 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 1,116,286 1,192 1,117,478 Other Assets Restricted cash 25,583 — 25,583 Other assets and debt issuance costs, net of accumulated amortization 28,244 — 28,244 Total Other Assets 53,827 — 53,827 Total Assets $ 1,485,462 $ (4,755) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 101,117 $ — $ 101,117 Accrued liabilities 63,660 (7,985) 55,675 Asset retirement obligations 56,601 — 56,601 Current maturities of long-term debt 4,268 — 4,268 Total Current Liabilities 225,646 (7,985) 217,661 Long-term debt, less current maturities 74,229 — 74,229 Asset retirement obligations 696,763 (16,256) 680,507 Other liabilities 14,481 (1,886) 12,595 Total Liabilities 1,011,119 (26,127) 984,992 Stockholders’ Equity Preferred stock — — — Common stock 332 — 332 Additional paid-in capital 880,286 21,372 901,658 Accumulated deficit (406,275) — (406,275) Total Stockholders’ Equity 474,343 21,372 495,715 Total Liabilities and Stockholders’ Equity $ 1,485,462 $ (4,755) $ 1,480,707 These adjustments impacted the consolidated statement of operations for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Revenues Oil sales $ 255,040 $ 1,010 $ 256,050 Natural gas liquids sales 3,533 — 3,533 Natural gas sales 37,103 — 37,103 Total Revenues 295,676 1,010 296,686 Costs and Expenses Lease operating 137,007 (429) 136,578 Production taxes 482 — 482 Gathering and transportation 5,910 — 5,910 Pipeline facility fee 20,330 — 20,330 Depreciation, depletion and amortization 60,626 (424) 60,202 Accretion of asset retirement obligations 38,973 (593) 38,380 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 General and administrative expense 27,557 — 27,557 Total Costs and Expenses 377,705 (10,485) 367,220 Operating Loss (82,029) 11,495 (70,534) Other Income (Expense) Other income, net 117 — 117 Interest expense (12,580) — (12,580) Total Other Expense, net (12,463) — (12,463) Loss Before Reorganization Items and Income Taxes (94,492) 11,495 (82,997) Reorganization items 2,748,395 (14,787) 2,733,608 Loss Before Income Taxes 2,653,903 (3,292) 2,650,611 Income Tax Expense — — — Net Income $ 2,653,903 $ (3,292) $ 2,650,611 Earnings per Share Basic $ 26.99 $ (0.04) $ 26.95 Diluted $ 25.33 $ (0.03) $ 25.30 Weighted Average Number of Common Shares Outstanding Basic 98,337 98,337 98,337 Diluted 104,787 104,787 104,787 These adjustments impacted the consolidated statement of cash flows for the six months ended December 31, 2016 as follows (in thousands): Predecessor Six Months Ended December 31, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net income $ 2,653,903 $ (3,292) $ 2,650,611 Adjustments to reconcile net income to net cash used in operating activities: Depreciation, depletion and amortization 60,626 (424) 60,202 Impairment of oil and natural gas properties 86,820 (9,039) 77,781 Accretion of asset retirement obligations 38,973 (593) 38,380 Reorganization items (2,838,963) 14,787 (2,824,176) Amortization and write-off of debt issuance costs, payment of interest in kind and other 5,025 — 5,025 Deferred rent 3,355 — 3,355 Stock-based compensation 183 — 183 Changes in operating assets and liabilities Accounts receivable (16,545) (1,010) (17,555) Prepaid expenses and other assets (7,425) — (7,425) Change in restricted cash (25,157) — (25,157) Settlement of asset retirement obligations (18,852) — (18,852) Accounts payable and accrued liabilities 40,584 (429) 40,155 Net Cash Used in Operating Activities (17,473) — (17,473) Cash Flows from Investing Activities Capital expenditures (20,237) — (20,237) Change in restricted cash 31,748 — 31,748 Other 195 — 195 Net Cash Provided by Investing Activities 11,706 — 11,706 Cash Flows from Financing Activities Payments on long-term debt (32,088) — (32,088) Other (35) — (35) Net Cash Used in Financing Activities (32,123) — (32,123) Net Decrease in Cash and Cash Equivalents (37,890) — (37,890) Cash and Cash Equivalents, beginning of period 203,258 203,258 Cash and Cash Equivalents, end of period $ 165,368 $ $ — $ 165,368 These adjustments impacted the consolidated statement of operations for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 531,914 $ 591 $ 532,505 Natural gas liquids sales 14,852 — 14,852 Natural gas sales 69,255 — 69,255 Gain on derivative financial instruments 90,506 — 90,506 Total Revenues 706,527 591 707,118 Costs and Expenses Lease operating 328,183 — 328,183 Production taxes 1,442 — 1,442 Gathering and transportation 33,156 — 33,156 Pipeline facility fee 40,659 — 40,659 Depreciation, depletion and amortization 339,516 23 339,539 Accretion of asset retirement obligations 64,690 18 64,708 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 General and administrative expense 102,736 — 102,736 Total Costs and Expenses 3,723,952 499 3,724,451 Operating Loss (3,017,425) 92 (3,017,333) Other (Expense) Income Loss from equity method investees (10,746) — (10,746) Other income, net 3,596 — 3,596 Gain on early extinguishment of debt 1,525,596 — 1,525,596 Interest expense (405,658) — (405,658) Total Other Income, net 1,112,788 — 1,112,788 Loss Before Reorganization Items and Income Taxes (1,904,637) 92 (1,904,545) Reorganization items (14,201) — (14,201) Loss Before Income Taxes (1,918,838) 92 (1,918,746) Income Tax Benefit (87) — (87) Net Loss (1,918,751) 92 (1,918,659) Preferred Stock Dividends 8,394 (3,200) 5,194 Net Loss Attributable to Common Stockholders $ (1,927,145) $ 3,292 $ (1,923,853) Loss per Share Basic and Diluted $ (20.11) $ 0.03 $ (20.08) Weighted Average Number of Common Shares Outstanding Basic and Diluted 95,822 95,822 95,822 These adjustments impacted the consolidated statement of cash flows for the year ended June 30, 2016 as follows (in thousands): Predecessor Year Ended June 30, 2016 As reported Adjustments As Revised Cash Flows From Operating Activities Net loss $ (1,918,751) $ 92 $ (1,918,659) Adjustments to reconcile net loss to net cash (used in) provided by operating activities: Depreciation, depletion and amortization 339,516 23 339,539 Impairment of oil and natural gas properties 2,813,570 458 2,814,028 Change in fair value of derivative financial instruments 19,163 — 19,163 Accretion of asset retirement obligations 64,690 18 64,708 Loss from equity method investees 10,746 — 10,746 Gain on early extinguishment of debt (1,525,596) — (1,525,596) Amortization and write-off of debt issuance costs, payment of interest in kind and other 138,473 — 138,473 Deferred rent 9,154 — 9,154 Provision for loss on accounts receivable 3,200 — 3,200 Stock-based compensation 1,336 — 1,336 Changes in operating assets and liabilities Accounts receivable 42,742 (591) 42,151 Prepaid expenses and other assets (24,438) — (24,438) Change in restricted cash — — — Settlement of asset retirement obligations (78,273) — (78,273) Accounts payable and accrued liabilities (62,187) — (62,187) Net Cash Used in Operating Activities (166,655) — (166,655) Cash Flows from Investing Activities Acquisitions, net of cash (2,797) — (2,797) Capital expenditures (111,884) — (111,884) Insurance payments received 8,251 — 8,251 Change in restricted cash (22,136) — (22,136) Proceeds from the sale of properties 5,693 — 5,693 Other (40) — (40) Net Cash Used in Investing Activities (122,913) — (122,913) Cash Flows from Financing Activities Proceeds from the issuance of common and preferred stock, net of offering costs 334 — 334 Dividends to shareholders – preferred (5,673) — (5,673) Proceeds from long-term debt 1,121 — 1,121 Payments on long-term debt (227,884) — (227,884) Payment of debt assumed in acquisition (25,187) — (25,187) Fees related to debt extinguishment (3,526) — (3,526) Debt issuance costs (2,163) — (2,163) Other (1,044) — (1,044) Net Cash Used in Financing Activities (264,022) — (264,022) Net Decrease in Cash and Cash Equivalents (553,590) — (553,590) Cash and Cash Equivalents, beginning of period 756,848 756,848 Cash and Cash Equivalents, end of period $ 203,258 $ $ — $ 203,258 |
Schedule of Cancellation of Indebtedness Income [Table Text Block] | Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 |
Fresh Start Accounting (Tables)
Fresh Start Accounting (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fresh Start Accounting | |
Schedule of reconciliation of the enterprise value to the estimated fair value of the Successor company's common stock as of the Convenience Date | The following table reconciles the enterprise value to the estimated fair value of the Successor Company’s common stock as of the Convenience Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Less: Fair value of debt (78,497) Fair Value of Successor common stock and warrants 901,990 Less: Fair value of warrants (8,056) Fair Value of Successor common stock $ 893,934 |
Schedule of reconciliation of enterprise value to estimated reorganization value as of the Emergence Date | The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date ( in thousands ): December 31, 2016 Enterprise Value $ 815,119 Add: Cash and cash equivalents 165,368 Add: Other working capital liabilities 156,792 Add: Other long-term liabilities 12,595 Add: Asset retirement obligation 737,108 Reorganization value of Successor assets $ 1,886,982 |
Schedule of reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on consolidated balance sheet | The following table reflects the reorganization and application of ASC 852 and the Convenience Date ceiling test impairment on our consolidated balance sheet as of December 31, 2016 after making adjustments to correct immaterial misstatements. For a detailed explanation of these adjustments, p lease see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements” ( in thousands ): As of December 31, 2016 Predecessor Reorganization Fresh-Start Successor Impairment Successor ASSETS Current Assets Cash and cash equivalents $ 164,817 $ 551 (1) $ — $ 165,368 $ — $ 165,368 Accounts receivable, net — — Oil and natural gas sales 69,744 — — 69,744 — 69,744 Joint interest billings 6,029 — — 6,029 — 6,029 Other 18,909 (965) (3) — 17,944 — 17,944 Prepaid expenses and other current assets 46,123 (26,260) (2) (1,883) (10) 17,980 — 17,980 Restricted cash 32,888 (551) (1) — 32,337 — 32,337 Total Current Assets 338,510 (27,225) (1,883) 309,402 — 309,402 Property and Equipment Oil and natural gas properties, net 491,521 — 1,012,225 (11) 1,503,746 (406,275) 1,097,471 Other property and equipment, net 15,049 — 4,958 (12) 20,007 — 20,007 Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment 506,570 — 1,017,183 1,523,753 (406,275) 1,117,478 Other Assets Restricted cash 25,583 — — 25,583 — 25,583 Other assets 30,174 — (1,930) (13) 28,244 — 28,244 Total Other Assets 55,757 — (1,930) 53,827 — 53,827 Total Assets $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current Liabilities Accounts payable $ 67,876 $ 33,241 (3) $ — $ 101,117 $ — $ 101,117 Accrued liabilities 40,517 15,158 (3)(4) — 55,675 — 55,675 Asset retirement obligations 58,537 — (1,936) (14) 56,601 — 56,601 Current maturities of long-term debt 74,046 (69,778) (5) — 4,268 — 4,268 Total Current Liabilities 240,976 (21,379) (1,936) 217,661 — 217,661 Long-term debt, less current maturities — 74,229 (5) — 74,229 — 74,229 Asset retirement obligations 492,931 — 187,576 (14) 680,507 — 680,507 Other liabilities 22,776 2,345 (3) (12,526) (15) 12,595 — 12,595 Total Liabilities Not Subject to Compromise 756,683 55,195 173,114 984,992 — 984,992 Liabilities subject to compromise 2,931,419 (2,931,419) (6) — — — — Total Liabilities 3,688,102 (2,876,224) 173,114 984,992 — 984,992 Stockholders’ Equity (Deficit) Preferred stock (Predecessor) 7.25% Convertible perpetual preferred stock (Predecessor) — — — — — — 5.625% Convertible perpetual preferred stock (Predecessor) — — — — — — Common stock (Predecessor) 504 (504) (7) — — — — Common stock (Successor) — 332 (8) — 332 — 332 Additional paid-in capital (Predecessor) 1,845,851 (1,845,851) (7) — — — — Additional paid-in capital (Successor) — 901,658 (8) — 901,658 — 901,658 Accumulated deficit (4,633,620) 3,793,364 (9) 840,256 (16) — (406,275) (406,275) Total Stockholders’ (Deficit) Equity (2,787,265) 2,848,999 840,256 901,990 (406,275) 495,715 Total Liabilities and Stockholders’ (Deficit) Equity $ 900,837 $ (27,225) $ 1,013,370 $ 1,886,982 $ (406,275) $ 1,480,707 Reorganization Adjustments (1) (2) (3) (4) (5) (6) in thousands ): On December 31, 2016 Predecessor Debt 11.0% Senior Secured Second Lien Notes due 2020 $ 1,450,000 8.25% Senior Notes due 2018 213,677 6.875% Senior Notes due 2024 143,993 3.0% Senior Convertible Notes due 2018 363,018 7.5% Senior Notes due 2021 238,071 7.75% Senior Notes due 2019 101,077 9.25% Senior Notes due 2017 249,452 4.14% Promissory Note due 2017 4,001 Capital lease obligations 450 Total debt 2,763,739 Accounts payable 37,424 Accrued liabilities 130,256 Total liabilities subject to compromise 2,931,419 Fair value of equity and warrants issued per the Plan (901,990) Fair value of reinstated accounts payable and accrued liabilities to be settled in cash (43,509) Cash payment for 3.0% Senior Convertible Notes (2,000) Gain on settlement of liabilities subject to compromise $ 1,983,920 (7) (8) (9) in thousands ): December 31, 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 Cancellation of EXXI Ltd equity 1,846,355 Accrual of success fee (12,651) Payments made of plan support parties (24,260) Net impact to accumulated deficit $ 3,793,364 Fresh Start Adjustments (10) (11) (12) (13) (14) 37.1 million. (15) (16) |
Schedule of reorganization items | The following table summarizes reorganization items ( in thousands ): Predecessor Six Months Ended Year Ended December 31, June 30, 2016 2016 Gain on settlement of liabilities subject to compromise $ 1,983,920 $ — Fresh start adjustments 840,256 — Reorganization legal and professional fees and expenses (90,568) (14,201) Gain (loss) on reorganization items $ 2,733,608 $ (14,201) |
Acquisitions and Dispositions (
Acquisitions and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions and Dispositions | |
Schedule of the final purchase price allocation of assets acquired and liabilities assumed | The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their estimated fair values on August 11, 2015 ( in thousands ): Oil and natural gas properties – evaluated $ 73,910 Oil and natural gas properties – unevaluated 39,278 Asset retirement obligations (66,700) Net working capital * (21,301) Fair value of debt assumed (25,187) Cash paid $ — * |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property and Equipment | |
Schedule of property and equipment | Property and equipment consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Oil and gas properties Proved properties $ 1,307,009 $ 1,127,608 Less: accumulated depreciation, depletion, amortization and impairment (742,286) (406,275) Proved properties, net 564,723 721,333 Unevaluated properties 200,199 376,138 Oil and gas properties, net 764,922 1,097,471 Other property and equipment 13,780 20,007 Less: accumulated depreciation (3,660) — Other property and equipment, net 10,120 20,007 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 775,042 $ 1,117,478 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-Term Debt | |
Schedule of long-term debt | Long-term debt consists of the following ( in thousands ): Successor December 31, December 31, 2017 2016 Exit Facility $ 73,996 $ 73,996 4.14% Promissory Note due 2017 — 4,001 Capital lease obligations 21 500 Total debt 74,017 78,497 Less: debt issue costs 44 — Less: current maturities 21 4,268 Total long-term debt $ 73,952 $ 74,229 |
Schedule of maturities of long-term debt | Maturities of long-term debt as of December 31, 2017 are as follows (in thousands ) Twelve Months Ending December 31, 2018 $ 21 2019 73,996 2020 — 2021 — 2022 — Thereafter — $ 74,017 |
Schedule of cancelled obligations under debt instruments | Issue Date Face value Maturity Date 11.0% Senior Secured Second Lien Notes 3/12/2015 1,450,000 3/15/2020 8.25% Senior Notes (1) 6/3/2014 510,000 2/15/2018 6.875% Senior Notes 5/27/2014 650,000 3/15/2024 3.0% Senior Convertible Notes 11/18/2013 400,000 12/15/2018 7.5% Senior Notes 9/26/2013 500,000 12/15/2021 7.75% Senior Notes 2/25/2011 250,000 6/15/2019 9.25% Senior Notes 12/17/2010 750,000 12/15/2017 (1) 8.25% Senior Notes was assumed in the EPL Acquisition. |
Schedule of interest expense | Interest expense consisted of the following ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Exit Term Loan $ 4,050 $ — $ — $ — Exit Revolving Facility 10,127 — — — Prepetition Revolving Credit Facility — 11,670 15,703 25,506 11.0% Second Lien Notes due 2020 — — 125,852 48,505 8.25% Senior Notes due 2018 — — 27,899 42,075 6.875% Senior Notes due 2024 — — 18,033 44,701 3.0% Senior Convertible Notes due 2018 — — 9,340 12,000 7.50% Senior Notes due 2021 — — 17,414 37,500 7.75% Senior Notes due 2019 — — 8,200 19,375 9.25% Senior Notes due 2017 — — 44,944 69,375 4.14% Promissory Note due 2017 134 — 130 192 Amortization of debt issue cost - Prepetition Revolving Credit Facility — 725 5,185 12,491 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 — — 6,249 2,358 Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 - accelerated — — 44,855 — Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 — — 5,047 1,887 Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 - accelerated — — 36,243 — Amortization of fair value premium – 8.25% Senior Notes due 2018 — — (8,818) (11,108) Amortization of fair value premium – 8.25% Senior Notes due 2018 - accelerated — — (7,961) — Amortization of debt issue cost – 6.875% Senior Notes due 2024 — — 457 1,127 Amortization of debt issue cost – 6.875% Senior Notes due 2024 - accelerated — — 1,946 — Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 — — 8,917 11,232 Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 - accelerated — — 33,370 — Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 — — 1,142 1,439 Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 - accelerated — — 4,271 — Amortization of debt issue cost – 7.50% Senior Notes due 2021 — — 478 1,051 Amortization of debt issue cost – 7.50% Senior Notes due 2021 - accelerated — — 2,822 — Amortization of debt issue cost – 7.75% Senior Notes due 2019 — — 168 388 Amortization of debt issue cost – 7.75% Senior Notes due 2019 - accelerated — — 491 — Amortization of debt issue cost – 9.25% Senior Notes due 2017 — — 1,902 2,358 Amortization of debt issue cost – 9.25% Senior Notes due 2017 - accelerated — — 913 — Derivative instruments financing and other 525 185 466 856 $ 14,836 $ 12,580 $ 405,658 $ 323,308 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligations | |
Schedule of changes in asset retirement obligations | The following table describes the changes in our asset retirement obligations ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, 2017 2016 Beginning of period total $ 737,108 $ 537,637 Liabilities incurred 11,353 13,880 Liabilities settled (55,820) (18,852) Revisions* (70,570) (19,577) Accretion expense 42,780 38,380 End of period total 551,468 Fair value fresh start adjustments 185,640 End of period total 664,851 737,108 Less: End of period, current portion 51,398 56,601 End of period, noncurrent portion $ 613,453 $ 680,507 * , resulting from updated estimates as to when the associated wells would cease to be economic, and the downward revision for the six months ended December 31, 2016 was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity. |
Derivative Financial Instrume40
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Financial Instruments | |
Schedule of derivative positions | As of December 31, 2017, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59 |
Schedule of fair value of our derivative instruments | Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps January 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 January 2018 - June 2018 Swaps Argus-LLS $ 55.45 January 2018 - June 2018 Swaps ICE Brent $ 56.59 The fair value of our derivative instruments in our consolidated balance sheets were as follows ( in thousands ) Successor Asset Derivative Instruments Liability Derivative Instruments December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ — Current $ — Current $ 32,567 Current $ — Non-Current — Non-Current — Non-Current — Non-Current — Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement — — 32,567 — Derivative financial instruments Current — Current — Current — Current — Non-Current — Non-Current — Non-Current — Non-Current — Total gross amounts offset in Balance Sheets — — — — Net amounts presented in Balance Sheets Current — Current — Current 32,567 Current — Non-Current — Non-Current — Non-Current — Non-Current — $ — $ — $ 32,567 $ — |
Schedule of the components of the gain (loss) on derivative instruments | The following table presents information about the components of the gain (loss) on derivative instruments ( in thousands ). Year Ended Six Months December 31, Ended Year Ended June 30, Gain (loss) on derivative financial instruments 2017 2016 2016 2015 Cash Settlements $ (58) $ — $ 59,081 $ 81,049 Proceeds from monetizations — — 50,588 102,354 Change in fair value (32,567) — (19,163) 52,036 Total gain (loss) on derivative financial instruments $ (32,625) $ — $ 90,506 $ 235,439 |
Supplemental Cash Flow Inform41
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information | |
Schedule of supplemental cash flow information | The following table presents our supplemental cash flow information ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Cash paid for interest $ 14,867 $ 7,493 $ 229,569 $ 243,238 Cash paid for income taxes — — 150 933 |
Schedule of non-cash investing and financing activities | The following table presents our non-cash investing and financing activities ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Derivative instruments premium financing $ — $ — $ — $ 12,025 Changes in capital expenditures accrued in accounts payable (1,944) 10,242 (37,151) (168,569) Acquisition of property against joint interest billings receivable (1,500) — — Inventory transferred to oil and natural gas properties — — 7,081 — Changes in asset retirement obligations (59,217) (5,697) (2,583) 49,495 Changes in other property and equipment (327) Monetization of derivative instruments applied to Revolving Credit Facility — — 50,588 — |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans | |
Schedule of stock option activity | Weighted Weighted Average Average Remaining Exercise Price Contractual Options Per Share Terms (in years) Outstanding as of December 31, 2016 - $ — — Granted 372,597 28.92 Exercised - - Forfeited (72,448) 28.97 Outstanding as of December 31, 2017 300,149 $ 28.91 9.3 Exercisable on December 31, 2017 — $ — |
Schedule of restricted stock units activity | Restricted Average Stock Grant Date Units Fair Value Outstanding as of December 31, 2016 - $ — Granted 775,344 24.22 Vested (68,814) 24.21 Forfeited (93,730) 24.48 Outstanding as of December 31, 2017 612,800 $ 24.19 |
Schedule of stock-based compensation expense | The following table sets forth stock-based compensation expense ( in thousands ): Successor Year Ended December 31, 2017 Stock Options $ 1,453 Restricted Stock Units 8,033 Total compensation expense recognized $ 9,486 |
Schedule of contributions under plans | The contributions under these plans were as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2017 2016 2016 2015 Profit Sharing Plan $ — $ — $ — $ — $ (768) 401(k) Plan 1,702 — 638 2,852 3,192 Total contributions $ 1,702 $ — $ 638 $ 2,852 $ 2,424 |
Earnings (Loss) per Share (Tabl
Earnings (Loss) per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings (Loss) per Share | |
Schedule of basic and diluted earnings (loss) per share | The following table sets forth the calculation of basic and diluted (loss) earnings per share (“EPS”) ( in thousands, except per share data ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Net (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,659) $ (2,433,838) Preferred stock dividends — — — 5,194 11,468 Net (loss) income attributable to common stockholders $ (341,010) $ (406,275) $ 2,650,611 $ (1,923,853) $ (2,445,306) Weighted average shares outstanding for basic EPS 33,239 33,212 98,337 95,822 94,167 Add dilutive securities — — 6,450 — — Weighted average shares outstanding for diluted EPS 33,239 33,212 104,787 95,822 94,167 (Loss) earnings per share Basic $ (10.26) $ (12.23) $ 26.95 $ (20.08) $ (25.97) Diluted $ (10.26) $ (12.23) $ 25.30 $ (20.08) $ (25.97) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies | |
Schedule of future minimum lease commitments under operating leases | As of December 31, 2017, future minimum lease commitments under our operating leases are as follows ( in thousands ): Year Ending December 31, Successor 2018 $ 36,035 2019 36,509 2020 43,545 2021 49,598 2022 48,575 Thereafter 152,176 Total $ 366,438 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Taxes | |
Schedule of Cancellation of Indebtedness Income | Successor After Return to Provision As Filed Adjustment (in thousands) Pre-tax reductions in: Net operating loss carryovers $ 486 $ 681 Oil and natural gas properties 1,485 915 EPL stock basis 543 304 Other 67 18 CODI excluded requiring attribute reduction $ 2,581 $ 1,918 |
Schedule of income (loss) before income taxes | Our (loss) income before income taxes attributable to U.S. and non-U.S. operations are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 U.S. (loss) income $ (341,010) $ (406,275) $ 2,650,611 $ (1,913,626) $ (3,050,659) Non-U.S. (loss) income — — — (5,120) 3,471 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) |
Schedule of the components of income tax expense (benefit) | The components of our income tax benefit are as follows ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 Current U.S. $ — $ — $ — $ — $ 933 Non U.S. — — — — — State — — — (87) 99 Total current — — — (87) 1,032 Deferred U.S. — — — — (564,569) State — — — — (49,813) Total deferred — — — — (614,382) Total income tax benefit $ — $ — $ — $ (87) $ (613,350) |
Schedule of the reconciliation of statutory income tax expense to the income tax provision (benefit) | The following is a reconciliation of statutory income tax expense to our income tax benefit ( in thousands ): Successor Predecessor Year Ended On Six Months Ended December 31, December 31, December 31, Year Ended June 30, 2017 2016 2016 2016 2015 (Loss) income before income taxes $ (341,010) $ (406,275) $ 2,650,611 $ (1,918,746) $ (3,047,188) Statutory rate 35 % 35 % 35 % 35 % 35 % Income tax (benefit) expense computed at statutory rate (119,354) (142,196) 927,714 (671,561) (1,066,516) Reconciling items Federal withholding obligation — — — 8,161 10,331 Nontaxable foreign income — — — 1,791 91 Change in valuation allowance 138,561 142,196 (1,029,335) 650,011 356,798 State income taxes (benefit), net of federal tax benefit — — — (87) (32,314) Non-deductible transaction and restructuring costs 894 — 36,874 — 440 Return to provision adjustments (224,339) — — — — Tax Cuts and Jobs Act of 2017 204,137 — — — — Tax basis in shortfall on partnership dissolution — — — 6,501 — Fresh start adjustments to deferred tax balances: Asset retirement obligation — — 190,715 — — Net operating loss — — 163,027 — — Accrued interest expense — — 115,560 — — Oil and natural gas properties and other property and equipment — — 611,834 — — Deferred state income taxes — — 54,793 — — Withholding taxes — — (81,635) — — Cancellation of stockholders deficit — — (290,665) — — Cancellation of indebtedness income — — (702,972) — — Other fresh start deferred income taxes, net — — 3,284 — — Goodwill impairment — — — — 115,253 Other – Net 101 — 806 5,097 2,567 Income tax benefit $ — $ — $ — $ (87) $ (613,350) |
Schedule of the components of deferred taxes | The components of deferred taxes are detailed in the table below ( in thousands ): Successor December 31, 2017 2016 Deferred tax assets – non current Oil, natural gas properties and other property and equipment $ 66,297 $ — Asset retirement obligation 139,619 257,988 Tax loss carryforwards on U.S. operations 71,268 — Employee benefit plans 1,698 — Tax partnership activity 676 — Derivative instruments and other 6,839 — Other 19,809 11,120 Total deferred tax assets – non current 306,206 269,108 Deferred tax liabilities Oil, natural gas properties and other property and equipment — (101,463) Total deferred tax liabilities – non current — (101,463) Valuation allowance (306,206) (167,645) Net deferred tax $ — $ — |
Fair Value (Tables)
Fair Value (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value | |
Schedule of the fair value of Level 1 and Level 2 financial instruments | The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Successor Level 2 As of As of December 31, December 31, 2017 2016 Assets: Oil and natural gas derivatives $ — $ — Liabilities: Oil and natural gas derivatives $ 32,567 $ — |
Schedule of details of Level 2 financial instruments | The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): Successor December 31, 2017 2016 Carrying Value Estimated Carrying Value Estimated Exit Facility $ 73,996 $ 73,996 $ 73,996 $ 73,996 Total $ 73,996 $ 73,996 $ 73,996 $ 73,996 (1) In accordance with the Plan, on the Emergence Date, all outstanding obligations under these notes and the related collateral agreements and registration rights, as applicable, were cancelled and the indentures governing such obligations were cancelled. |
Schedule of changes in Level 3 financial instruments | The following table sets forth our Level 3 financial instruments ( in thousands ): Predecessor Six Months Ended Year Ended Year Ended December 31, June 30, June 30, 2016 2016 2015 Liabilities: Performance-based performance units Balance at beginning of period $ — $ 33 $ 6,910 Vested — (775) — Grants charged to general and administrative expense — 760 (6,877) Balance at end of period $ — $ 18 $ 33 |
Prepayments and Accrued Liabi47
Prepayments and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Prepayments and Accrued Liabilities | |
Schedule of prepayments and accrued liabilities | Prepayments and accrued liabilities consist of the following ( in thousands ): Successor December 31, 2017 2016 Prepaid expenses and other current assets Advances to joint interest partners $ 1,381 $ 650 Insurance 5,949 9,600 Inventory 394 470 Royalty deposit 1,021 1,273 Other 12,857 5,987 Total prepaid expenses and other current assets $ 21,602 $ 17,980 Accrued liabilities Advances from joint interest partners 81 374 Employee benefits and payroll 6,791 4,491 Interest payable 185 233 Accrued hedge payable 2,491 — Undistributed oil and gas proceeds 20,079 22,715 Severance taxes payable 558 628 Escrowed reorganization expenses — 25,987 Other 15,309 1,247 Total accrued liabilities $ 45,494 $ 55,675 |
Comparative Period Information
Comparative Period Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Comparative Period Information | |
Schedule of transition and comparative period financial information | Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Total Revenues $ 296,686 $ 442,438 Operating loss (70,534) (2,431,348) Income (loss) before income taxes 2,650,611 (1,883,924) Income tax expense (benefit) — 51 Net Income (loss) $ 2,650,611 $ (1,883,975) Preferred stock dividends — 5,664 Net Income (Loss) Attributable to Common Stockholders $ 2,650,611 $ (1,889,639) Earnings (Loss) per Share Basic $ 26.95 $ (19.91) Diluted $ 25.30 $ (19.91) Weighted Average Number of Common Shares Outstanding Basic 98,337 94,926 Diluted 104,787 94,926 Predecessor Six Months Ended December 31, 2016 (1) 2015 (2) (Unaudited) (In thousands) Net cash used in operating activities $ (17,473) $ (89,924) Net cash provided by (used in) investing activities 11,706 (82,872) Net cash used in financing activities (32,123) (258,162) Net decrease in cash and cash equivalents $ (37,890) $ (430,958) (1) Included in Operating income (loss) is impairment of oil and natural gas properties of $86.8 million and also included in Net income (loss) are reorganization items being gain on settlement of liabilities subject to compromise of $ 1.983.9 million, fair value adjustment of $8 40.3 and reorganization expenses of $90.6 million. (2) Included in Operating income (loss) is impairment of oil and natural gas properties of $2,330.5 million and also included in Net income (loss) is gain on early extinguishment of debt of $748.6 million. |
Selected Quarterly Financial 49
Selected Quarterly Financial Data – Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Data – Unaudited | |
Schedule of selected quarterly financial data (unaudited) | Unaudited quarterly financial data are as follows ( in thousands, except per share amounts ): Successor Quarter Ended December 31, (2) September 30, June 30, March 31, (3) 2017 2017 2017 2017 Revenues $ 93,838 $ 115,701 $ 144,019 $ 158,086 Operating loss (211,462) (31,556) (22,675) (60,735) Net loss $ (215,069) $ (35,157) $ (26,237) $ (64,547) Net loss per share (1) Basic and Diluted $ (6.47) $ (1.06) $ (0.79) $ (1.94) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income (loss) for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $1 45.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $40.8 million. We made adjustments to correct immaterial misstatements within our previously reported quarterly financial statements. These immaterial misstatements affected certain line items within the cash flow from operations section and did not change the total amount of previously reported cash flows. For a detailed explanation of these adjustments, please see Note 2 “—Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements.” Predecessor Quarter Ended December 31, (7) September 30, (6) June 30, (2) March 31, (3) December 31, (4) September 30, (5) 2016 2016 2016 2016 2015 2015 Revenues $ 153,723 $ 142,963 $ 148,395 $ 116,285 $ 184,615 $ 257,823 Operating income (loss) 12,795 (83,329) (168,119) (417,866) (1,513,148) (918,200) Net income (loss) $ 2,771,349 $ (120,738) $ (195,460) $ 160,776 $ (1,310,583) $ (573,392) Preferred stock dividends — — (2,848) 2,378 2,810 2,854 Net income (loss) attributable to common stockholders $ 2,771,349 $ (120,738) $ (192,612) $ 158,398 $ (1,313,393) $ (576,246) Net income (loss) per share attributable to common stockholders (1) Basic $ 28.04 $ (1.23) $ (1.97) $ 1.65 $ (13.81) $ (6.08) Diluted 26.45 (1.23) (1.97) 1.55 (13.81) (6.08) (1) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. (2) Included in Operating loss is impairment of oil and natural gas properties of $143.1 million. (3) Included in Operating loss is impairment of oil and natural gas properties of $340.5 million and also included in Net loss is gain on early extinguishment of debt of $777.0 million. (4) Included in Operating loss is impairment of oil and natural gas properties of $1,425.8 million and also included in Net loss is gain on early extinguishment of debt of $290.3 million. (5) Included in Operating loss is impairment of oil and natural gas properties of $904.7 million and also included in Net loss is gain on early extinguishment of debt of $458.3 million. (6) Included in Operating loss is impairment of oil and natural gas properties of $77.6 million and also included in Net loss is reorganization expenses of $32.6 million. (7) Included in Net income are gain on settlement of liabilities subject to compromise of $ 1,983.9 million, fair value adjustment gain of $840.3 million and reorganization expenses of $58.0 million. |
Schedule for the effect of prior period errors in our consolidated quarterly income statements | Successor Successor Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 114,991 $ (1,294) $ 113,697 $ 366,792 $ (818) $ 365,974 Natural gas liquids sales 2,209 — 2,209 6,806 — 6,806 Natural gas sales 12,261 — 12,261 44,382 — 44,382 Gain on derivative financial instruments (12,466) — (12,466) 644 — 644 Total Revenues 116,995 (1,294) 115,701 418,624 (818) 417,806 Costs and Expenses Lease operating 77,822 — 77,822 238,315 429 238,744 Production taxes 471 — 471 1,192 — 1,192 Gathering and transportation (2,441) — (2,441) 11,459 — 11,459 Pipeline facility fee 10,495 — 10,495 31,483 — 31,483 Depreciation, depletion and amortization 36,066 65 36,131 116,733 (21) 116,712 Accretion of asset retirement obligations 9,892 (139) 9,753 32,339 479 32,818 Impairment of oil and natural gas properties (2,357) 2,357 — 40,849 (75) 40,774 General and administrative expense 15,026 — 15,026 57,346 — 57,346 Reorganization items — — — (1,529) 3,773 2,244 Total Costs and Expenses 144,974 2,283 147,257 528,187 4,585 532,772 Operating Loss (27,979) (3,577) (31,556) (109,563) (5,403) (114,966) Other Income (Expense) Other income, net 52 — 52 154 — 154 Interest expense (3,653) — (3,653) (11,129) — (11,129) Total Other Expense , net (3,601) — (3,601) (10,975) — (10,975) Loss Before Income Taxes (31,580) (3,577) (35,157) (120,538) (5,403) (125,941) Income Tax Expense — — — — — — Net Loss $ (31,580) $ (3,577) $ (35,157) $ (120,538) $ (5,403) $ (125,941) Loss per Share Basic and Diluted $ (0.95) $ (0.11) $ (1.06) $ (3.63) $ (0.16) $ (3.79) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,241 33,241 33,241 33,236 33,236 33,236 Successor Successor Three Months Ended June 30, 2017 Six Months Ended June 30, 2017 As reported Adjustments As Revised As reported Adjustments As Revised Revenues Oil sales $ 118,180 $ 304 $ 118,484 $ 251,801 $ 476 $ 252,277 Natural gas liquids sales 2,370 — 2,370 4,597 — 4,597 Natural gas sales 13,753 — 13,753 32,121 — 32,121 Gain on derivative financial instruments 9,412 — 9,412 13,110 — 13,110 Total Revenues 143,715 304 144,019 301,629 476 302,105 Costs and Expenses Lease operating 85,336 (1,681) 83,655 160,493 429 160,922 Production taxes 482 — 482 721 — 721 Gathering and transportation 2,678 — 2,678 13,900 — 13,900 Pipeline facility fee 10,494 — 10,494 20,988 — 20,988 Depreciation, depletion and amortization 38,661 24 38,685 80,667 (86) 80,581 Accretion of asset retirement obligations 10,050 (66) 9,984 22,447 618 23,065 Impairment of oil and natural gas properties (848) 848 — 43,206 (2,432) 40,774 General and administrative expense 20,716 — 20,716 42,320 — 42,320 Reorganization items (3,773) 3,773 — (1,529) 3,773 2,244 Total Costs and Expenses 163,796 2,898 166,694 383,213 2,302 385,515 Operating Loss (20,081) (2,594) (22,675) (81,584) (1,826) (83,410) Other Income (Expense) Other income, net 80 — 80 102 — 102 Interest expense (3,642) — (3,642) (7,476) — (7,476) Total Other Expense , net (3,562) — (3,562) (7,374) — (7,374) Loss Before Income Taxes (23,643) (2,594) (26,237) (88,958) (1,826) (90,784) Income Tax Expense — — — — — — Net Loss $ (23,643) $ (2,594) $ (26,237) $ (88,958) $ (1,826) $ (90,784) Loss per Share Basic and Diluted $ (0.71) $ (0.08) $ (0.79) $ (2.68) $ (0.05) $ (2.73) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,237 33,237 33,237 33,234 33,234 33,234 Successor Three Months Ended March 31, 2017 As reported Adjustments As Revised Revenues Oil sales $ 133,621 $ 172 $ 133,793 Natural gas liquids sales 2,227 — 2,227 Natural gas sales 18,368 — 18,368 Gain on derivative financial instruments 3,698 — 3,698 Total Revenues 157,914 172 158,086 Costs and Expenses Lease operating 75,157 2,110 77,267 Production taxes 239 — 239 Gathering and transportation 11,222 — 11,222 Pipeline facility fee 10,494 — 10,494 Depreciation, depletion and amortization 42,006 (110) 41,896 Accretion of asset retirement obligations 12,397 684 13,081 Impairment of oil and natural gas properties 44,054 (3,280) 40,774 General and administrative expense 23,848 — 23,848 Total Costs and Expenses 219,417 (596) 218,821 Operating Loss (61,503) 768 (60,735) Other Income (Expense) Other income, net 22 — 22 Interest expense (3,834) — (3,834) Total Other Expense , net (3,812) — (3,812) Loss Before Income Taxes (65,315) 768 (64,547) Income Tax Expense — — — Net Loss $ (65,315) $ 768 $ (64,547) Loss per Share Basic and Diluted $ (1.97) $ 0.02 $ (1.94) Weighted Average Number of Common Shares Outstanding Basic and Diluted 33,228 33,228 33,228 Predecessor Three Months Ended December 31, 2016 As reported Adjustments As Revised Revenues $ 153,065 $ 658 $ 153,723 Operating income 11,708 1,087 12,795 Net income $ 2,785,049 (13,700) $ 2,771,349 Income per Share Basic $ 28.17 $ (0.14) $ 28.04 Diluted $ 26.58 $ (0.13) $ 26.45 Weighted Average Number of Common Shares Outstanding Basic 98,850 98,850 98,850 Diluted 104,787 104,787 104,787 Predecessor Three Months Ended September 30, 2016 As reported Adjustments As Revised Revenues Oil sales $ 122,732 $ 352 $ 123,084 Natural gas liquids sales 2,144 — 2,144 Natural gas sales 17,735 — 17,735 Gain on derivative financial instruments — — — Total Revenues 142,611 352 142,963 Costs and Expenses Lease operating 65,170 — 65,170 Production taxes 214 — 214 Gathering and transportation 7,534 — 7,534 Pipeline facility fee 10,165 — 10,165 Depreciation, depletion and amortization 31,573 (432) 31,141 Accretion of asset retirement obligations 19,437 (362) 19,075 Impairment of oil and natural gas properties 86,820 (9,262) 77,558 General and administrative expense 15,435 — 15,435 Total Costs and Expenses 236,348 (10,056) 226,292 Operating Loss (93,737) 10,408 (83,329) Other Income (Expense) Other income, net 62 — 62 Interest expense (4,838) — (4,838) Total Other Expense , net (4,776) — (4,776) Loss Before Reorganization Items and Income Taxes (98,513) 10,408 (88,105) Reorganization items (32,633) — (32,633) Loss Before Income Taxes (131,146) 10,408 (120,738) Income Tax Expense — — — Net Loss $ (131,146) $ 10,408 $ (120,738) Loss per Share Basic and Diluted $ (1.34) $ 0.11 $ (1.23) Weighted Average Number of Common Shares Outstanding Basic and Diluted 97,824 97,824 97,824 |
Supplementary Oil and Gas Inf50
Supplementary Oil and Gas Information – Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplementary Oil and Gas Information – Unaudited | |
Schedule of costs incurred for oil and natural gas property acquisition, exploration and development activities | Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Property acquisitions Proved $ 96 $ 1,500 $ 26,400 $ — Unevaluated — — — 2,304 Exploration costs 669 — 1,400 38,183 Development costs 62,283 22,300 57,400 608,605 |
Schedule of estimated quantities of proved and undeveloped domestic oil and natural gas reserves | Natural Gas Oil Liquids Natural Gas Total (MBbls) (MBbls) (MMcf) (MBOE) Proved reserves at June 30, 2014 (Predecessor) 175,816 9,573 364,856 246,198 Production (14,272) (987) (37,472) (21,504) Extensions, discoveries and other additions 10,056 517 40,330 17,295 Revisions of previous estimates (32,115) (1,615) (75,617) (46,333) Sales of reserves (9,889) (12) (13,554) (12,160) Proved reserves at June 30, 2015 (Predecessor) 129,596 7,476 278,543 183,496 Production (12,624) (923) (33,973) (19,209) Extensions, discoveries and other additions 1,370 46 1,729 1,704 Revisions of previous estimates (61,347) (3,237) (158,681) (91,031) Purchases of reserves 5,145 871 33,529 11,604 Proved reserves at June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 Production (5,482) (167) (13,485) (7,897) Extensions, discoveries and other additions 31,846 375 27,788 36,852 Revisions of previous estimates 6,746 (1,293) 5,788 6,418 Proved reserves at December 31, 2016 (Successor) 95,250 3,148 141,238 121,937 Production (9,324) (288) (17,282) (12,493) Extensions, discoveries and other additions 5,691 217 7,030 7,082 Revisions of previous estimates (17,261) (1,397) (58,001) (28,327) Proved reserves at December 31, 2017 (Successor) 74,356 1,680 72,985 88,199 Proved developed reserves June 30, 2014 (Predecessor) 106,900 5,889 222,916 149,942 June 30, 2015 (Predecessor) 88,607 5,406 187,993 125,345 June 30, 2016 (Predecessor) 62,140 4,233 121,147 86,564 December 31, 2016 (Successor) 63,728 2,777 113,603 85,439 December 31, 2017 (Successor) 55,005 1,335 58,918 66,160 Proved undeveloped reserves June 30, 2014 (Predecessor) 68,916 3,684 141,940 96,256 June 30, 2015 (Predecessor) 40,989 2,070 90,550 58,151 June 30, 2016 (Predecessor) — — — — December 31, 2016 (Successor) 31,522 371 27,635 36,498 December 31, 2017 (Successor) 19,351 345 14,067 22,039 |
Schedule of the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves | The standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor As of As of As of December 31, December 31, June 30, 2017 2016 2016 2015 Future cash inflows $ 4,044,208 $ 4,344,985 $ 2,966,317 $ 10,641,151 Less related future Production costs 2,714,819 2,648,363 2,223,645 4,131,526 Development and abandonment costs 1,425,847 1,571,271 1,033,717 1,970,526 Income taxes — — — 168,655 Future net cash flows (96,458) 125,351 (291,045) 4,370,444 Less: Ten percent annual discount for estimated timing of cash flows (111,594) (23,494) (349,398) 1,613,034 Standardized measure of discounted future net cash flows (Predecessor) $ 58,353 $ 2,757,410 Standardized measure of discounted future net cash flows (Successor) $ 15,136 $ 148,845 |
Schedule of the summary of changes in the standardized measure of discounted future cash flows applicable to proved oil and natural gas reserves | A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows ( in thousands ): Successor Predecessor Year Ended Six Months Ended December 31, December 31, Year Ended June 30, 2017 2016 2016 2015 Beginning of period (Predecessor) $ 148,845 $ 58,353 $ 2,757,410 $ 5,947,525 Revisions of previous estimates Changes in prices and costs 252,357 (104,993) (3,287,459) (2,959,883) Changes in quantities (198,211) 53,585 (214,631) (2,390,099) Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs 8,908 325,892 26,911 201,234 Purchases (sales) of reserves in place — — 212,961 (244,507) Accretion of discount 14,885 (893) 215,297 760,175 Sales, net of production and gathering and transportation costs (224,976) (131,947) (212,581) (676,949) Net change in income taxes — — 77,025 1,576,954 Changes in rate of production and other (22,862) (2,704) 4,189 (191,668) Development costs incurred 3,878 11,283 10,493 237,173 Changes in estimated future development and abandonment costs 32,312 (59,731) 468,738 497,455 Net change (133,709) 90,492 (2,699,057) (3,190,115) End of period (Predecessor) $ 58,353 $ 2,757,410 End of period (Successor) $ 15,136 $ 148,845 |
Organization (Details)
Organization (Details) | 12 Months Ended |
Dec. 31, 2017ft | |
Maximum | |
Oil and natural gas properties | |
Off shore oil and gas properties, Depth of water (in feet) | 1,000 |
Revision of Prior Period Fina52
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Financial Statements (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2017 | Jun. 30, 2016 |
Revision of Prior Period Financial Statements | ||||||||||||
Net income (loss) | $ (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | $ (341,010) | |||
Asset retirement obligations | 680,507 | 613,453 | $ 680,507 | 680,507 | 613,453 | |||||||
Additional paid-in capital | 901,658 | $ 911,144 | 901,658 | 901,658 | $ 911,144 | |||||||
Adjustment | ||||||||||||
Revision of Prior Period Financial Statements | ||||||||||||
Net income (loss) | $ (3,577) | $ (2,594) | $ 768 | $ (1,826) | $ (5,403) | |||||||
Asset retirement obligations | (16,256) | (16,256) | (16,256) | |||||||||
Additional paid-in capital | $ 21,372 | 21,372 | 21,372 | |||||||||
Predecessor | ||||||||||||
Revision of Prior Period Financial Statements | ||||||||||||
Net income (loss) | 2,771,349 | $ (120,738) | 2,650,611 | $ (1,918,659) | ||||||||
Predecessor | Adjustment | ||||||||||||
Revision of Prior Period Financial Statements | ||||||||||||
Net income (loss) | $ (13,700) | $ 10,408 | $ (3,292) | $ 92 |
Revision of Prior Period Fina53
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 151,729 | $ 165,368 |
Accounts receivable, net | ||
Oil and natural gas sales | 55,598 | 69,744 |
Joint interest billings | 6,336 | 6,029 |
Other | 15,726 | 17,944 |
Prepaid expenses and other current assets | 21,602 | 17,980 |
Restricted cash | 6,392 | 32,337 |
Total Current Assets | 257,383 | 309,402 |
Property and Equipment | ||
Oil and natural gas properties, net | 764,922 | 1,097,471 |
Other property and equipment, net | 10,120 | 20,007 |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 775,042 | 1,117,478 |
Other Assets | ||
Restricted cash | 25,712 | 25,583 |
Other assets and debt issuance costs, net of accumulated amortization | 18,845 | 28,244 |
Total Other Assets | 44,557 | 53,827 |
Total Assets | 1,076,982 | 1,480,707 |
Current Liabilities | ||
Accounts payable | 85,122 | 101,117 |
Accrued liabilities | 45,494 | 55,675 |
Asset retirement obligations | 51,398 | 56,601 |
Current maturities of long-term debt | 21 | 4,268 |
Total Current Liabilities | 214,602 | 217,661 |
Long-term debt, less current maturities | 73,952 | 74,229 |
Asset retirement obligations | 613,453 | 680,507 |
Other liabilities | 10,783 | 12,595 |
Total Liabilities | 912,790 | 984,992 |
Stockholders' Equity | ||
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively | 333 | 332 |
Additional paid-in capital | 911,144 | 901,658 |
Accumulated deficit | (747,285) | (406,275) |
Total Stockholders' Equity | 164,192 | 495,715 |
Total Liabilities and Stockholders' Equity | $ 1,076,982 | 1,480,707 |
As reported | ||
Current Assets | ||
Cash and cash equivalents | 165,368 | |
Accounts receivable, net | ||
Oil and natural gas sales | 68,143 | |
Joint interest billings | 5,600 | |
Other | 17,944 | |
Prepaid expenses and other current assets | 25,957 | |
Restricted cash | 32,337 | |
Total Current Assets | 315,349 | |
Property and Equipment | ||
Oil and natural gas properties, net | 1,097,479 | |
Other property and equipment, net | 18,807 | |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 1,116,286 | |
Other Assets | ||
Restricted cash | 25,583 | |
Other assets and debt issuance costs, net of accumulated amortization | 28,244 | |
Total Other Assets | 53,827 | |
Total Assets | 1,485,462 | |
Current Liabilities | ||
Accounts payable | 101,117 | |
Accrued liabilities | 63,660 | |
Asset retirement obligations | 56,601 | |
Current maturities of long-term debt | 4,268 | |
Total Current Liabilities | 225,646 | |
Long-term debt, less current maturities | 74,229 | |
Asset retirement obligations | 696,763 | |
Other liabilities | 14,481 | |
Total Liabilities | 1,011,119 | |
Stockholders' Equity | ||
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,254,963 and 33,211,594 shares issued and outstanding at December 31, 2017 and December 31, 2016, respectively | 332 | |
Additional paid-in capital | 880,286 | |
Accumulated deficit | (406,275) | |
Total Stockholders' Equity | 474,343 | |
Total Liabilities and Stockholders' Equity | 1,485,462 | |
Adjustment | ||
Accounts receivable, net | ||
Oil and natural gas sales | 1,601 | |
Joint interest billings | 429 | |
Prepaid expenses and other current assets | (7,977) | |
Total Current Assets | (5,947) | |
Property and Equipment | ||
Oil and natural gas properties, net | (8) | |
Other property and equipment, net | 1,200 | |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 1,192 | |
Other Assets | ||
Total Assets | (4,755) | |
Current Liabilities | ||
Accrued liabilities | (7,985) | |
Total Current Liabilities | (7,985) | |
Asset retirement obligations | (16,256) | |
Other liabilities | (1,886) | |
Total Liabilities | (26,127) | |
Stockholders' Equity | ||
Additional paid-in capital | 21,372 | |
Total Stockholders' Equity | 21,372 | |
Total Liabilities and Stockholders' Equity | $ (4,755) |
Revision of Prior Period Fina54
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Income Statement (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 |
Revenues | |||||||||||||
Oil sales | $ 113,697 | $ 118,484 | $ 133,793 | $ 252,277 | $ 365,974 | $ 481,922 | |||||||
Natural gas liquids sales | 2,209 | 2,370 | 2,227 | 4,597 | 6,806 | 8,542 | |||||||
Natural gas sales | 12,261 | 13,753 | 18,368 | 32,121 | 44,382 | 53,805 | |||||||
Gain on derivative financial instruments | (12,466) | 9,412 | 3,698 | 13,110 | 644 | (32,625) | |||||||
Total Revenues | 115,701 | 144,019 | 158,086 | 302,105 | 417,806 | 511,644 | |||||||
Costs and Expenses | |||||||||||||
Lease operating | 77,822 | 83,655 | 77,267 | 160,922 | 238,744 | 319,671 | |||||||
Production taxes | 471 | 482 | 239 | 721 | 1,192 | 1,355 | |||||||
Gathering and transportation | (2,441) | 2,678 | 11,222 | 13,900 | 11,459 | 21,666 | |||||||
Pipeline facility fee | 10,495 | 10,494 | 10,494 | 20,988 | 31,483 | 41,977 | |||||||
Depreciation, depletion and amortization | 36,131 | 38,685 | 41,896 | 80,581 | 116,712 | 150,151 | |||||||
Accretion of asset retirement obligations | 9,753 | 9,984 | 13,081 | 23,065 | 32,818 | 42,780 | |||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | 40,774 | 40,774 | 40,774 | 185,860 | $ 406,300 | ||||||
General and administrative expense | 15,026 | 20,716 | 23,848 | 42,320 | 57,346 | 72,057 | |||||||
Total Costs and Expenses | 406,275 | 147,257 | 166,694 | 218,821 | 385,515 | 532,772 | 838,072 | ||||||
Operating Loss | (406,275) | (211,462) | (31,556) | (22,675) | (60,735) | (83,410) | (114,966) | (326,428) | |||||
Other (Expense) Income | |||||||||||||
Other income, net | 52 | 80 | 22 | 102 | 154 | 254 | |||||||
Interest expense | (3,653) | (3,642) | (3,834) | (7,476) | (11,129) | (14,836) | |||||||
Total Other (Expense) Income, net | (3,601) | (3,562) | (3,812) | (7,374) | (10,975) | (14,582) | |||||||
Loss Before Reorganization Items and Income Taxes | (406,275) | (341,010) | |||||||||||
(Loss) Income Before Income Taxes | (406,275) | (35,157) | (26,237) | (64,547) | (90,784) | (125,941) | (341,010) | ||||||
Income Tax Benefit | 0 | ||||||||||||
Net (Loss) Income | (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | (341,010) | ||||
Net (Loss) Income Attributable to Common Stockholders | $ (406,275) | $ (341,010) | |||||||||||
(Loss) Earnings per Share | |||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||
Basic and Diluted (in dollars per share) | $ (6.47) | $ (1.06) | $ (0.79) | $ (1.94) | $ (2.73) | $ (3.79) | |||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic (in shares) | 33,212 | 33,239 | |||||||||||
Diluted (in shares) | 33,212 | 33,239 | |||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | ||||||||
Predecessor | |||||||||||||
Revenues | |||||||||||||
Oil sales | $ 123,084 | 256,050 | $ 532,505 | ||||||||||
Natural gas liquids sales | 2,144 | 3,533 | 14,852 | ||||||||||
Natural gas sales | 17,735 | 37,103 | 69,255 | ||||||||||
Gain on derivative financial instruments | 90,506 | ||||||||||||
Total Revenues | $ 153,723 | 142,963 | 296,686 | 707,118 | |||||||||
Costs and Expenses | |||||||||||||
Lease operating | 65,170 | 136,578 | 328,183 | ||||||||||
Production taxes | 214 | 482 | 1,442 | ||||||||||
Gathering and transportation | 7,534 | 5,910 | 33,156 | ||||||||||
Pipeline facility fee | 10,165 | 20,330 | 40,659 | ||||||||||
Depreciation, depletion and amortization | 31,141 | 60,202 | 339,539 | ||||||||||
Accretion of asset retirement obligations | 19,075 | 38,380 | 64,708 | ||||||||||
Impairment of oil and natural gas properties | 77,558 | 77,781 | 2,814,028 | ||||||||||
General and administrative expense | 15,435 | 27,557 | 102,736 | ||||||||||
Total Costs and Expenses | 226,292 | 367,220 | 3,724,451 | ||||||||||
Operating Loss | 12,795 | (83,329) | (70,534) | (3,017,333) | |||||||||
Other (Expense) Income | |||||||||||||
Loss from equity method investees | (10,746) | ||||||||||||
Other income, net | 62 | 117 | 3,596 | ||||||||||
Gains (Losses) on Extinguishment of Debt | 1,525,596 | ||||||||||||
Interest expense | (4,838) | (12,580) | (405,658) | ||||||||||
Total Other (Expense) Income, net | (4,776) | (12,463) | 1,112,788 | ||||||||||
Loss Before Reorganization Items and Income Taxes | (88,105) | (82,997) | (1,904,545) | ||||||||||
Reorganization items | (32,633) | 2,733,608 | (14,201) | ||||||||||
(Loss) Income Before Income Taxes | (120,738) | 2,650,611 | (1,918,746) | ||||||||||
Income Tax Benefit | (87) | ||||||||||||
Net (Loss) Income | $ 2,771,349 | $ (120,738) | $ 2,650,611 | (1,918,659) | |||||||||
Preferred Stock Dividends | 5,194 | ||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ (1,923,853) | ||||||||||||
(Loss) Earnings per Share | |||||||||||||
Basic (in dollars per share) | $ 28.04 | $ 26.95 | |||||||||||
Diluted (in dollars per share) | $ 26.45 | $ 25.30 | |||||||||||
Basic and Diluted (in dollars per share) | $ (1.23) | $ (20.08) | |||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic (in shares) | 98,850 | 98,337 | |||||||||||
Diluted (in shares) | 104,787 | 104,787 | |||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 | |||||||||||
As reported | |||||||||||||
Revenues | |||||||||||||
Oil sales | $ 114,991 | $ 118,180 | $ 133,621 | $ 251,801 | $ 366,792 | ||||||||
Natural gas liquids sales | 2,209 | 2,370 | 2,227 | 4,597 | 6,806 | ||||||||
Natural gas sales | 12,261 | 13,753 | 18,368 | 32,121 | 44,382 | ||||||||
Gain on derivative financial instruments | (12,466) | 9,412 | 3,698 | 13,110 | 644 | ||||||||
Total Revenues | 116,995 | 143,715 | 157,914 | 301,629 | 418,624 | ||||||||
Costs and Expenses | |||||||||||||
Lease operating | 77,822 | 85,336 | 75,157 | 160,493 | 238,315 | ||||||||
Production taxes | 471 | 482 | 239 | 721 | 1,192 | ||||||||
Gathering and transportation | (2,441) | 2,678 | 11,222 | 13,900 | 11,459 | ||||||||
Pipeline facility fee | 10,495 | 10,494 | 10,494 | 20,988 | 31,483 | ||||||||
Depreciation, depletion and amortization | 36,066 | 38,661 | 42,006 | 80,667 | 116,733 | ||||||||
Accretion of asset retirement obligations | 9,892 | 10,050 | 12,397 | 22,447 | 32,339 | ||||||||
Impairment of oil and natural gas properties | (2,357) | (848) | 44,054 | 43,206 | 40,849 | ||||||||
General and administrative expense | 15,026 | 20,716 | 23,848 | 42,320 | 57,346 | ||||||||
Total Costs and Expenses | 144,974 | 163,796 | 219,417 | 383,213 | 528,187 | ||||||||
Operating Loss | (27,979) | (20,081) | (61,503) | (81,584) | (109,563) | ||||||||
Other (Expense) Income | |||||||||||||
Other income, net | 52 | 80 | 22 | 102 | 154 | ||||||||
Interest expense | (3,653) | (3,642) | (3,834) | (7,476) | (11,129) | ||||||||
Total Other (Expense) Income, net | (3,601) | (3,562) | (3,812) | (7,374) | (10,975) | ||||||||
(Loss) Income Before Income Taxes | (31,580) | (23,643) | (65,315) | (88,958) | (120,538) | ||||||||
Net (Loss) Income | $ (31,580) | $ (23,643) | $ (65,315) | $ (88,958) | $ (120,538) | ||||||||
(Loss) Earnings per Share | |||||||||||||
Basic and Diluted (in dollars per share) | $ (0.95) | $ (0.71) | $ (1.97) | $ (2.68) | $ (3.63) | ||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | ||||||||
As reported | Predecessor | |||||||||||||
Revenues | |||||||||||||
Oil sales | $ 122,732 | $ 255,040 | $ 531,914 | ||||||||||
Natural gas liquids sales | 2,144 | 3,533 | 14,852 | ||||||||||
Natural gas sales | 17,735 | 37,103 | 69,255 | ||||||||||
Gain on derivative financial instruments | 90,506 | ||||||||||||
Total Revenues | $ 153,065 | 142,611 | 295,676 | 706,527 | |||||||||
Costs and Expenses | |||||||||||||
Lease operating | 65,170 | 137,007 | 328,183 | ||||||||||
Production taxes | 214 | 482 | 1,442 | ||||||||||
Gathering and transportation | 7,534 | 5,910 | 33,156 | ||||||||||
Pipeline facility fee | 10,165 | 20,330 | 40,659 | ||||||||||
Depreciation, depletion and amortization | 31,573 | 60,626 | 339,516 | ||||||||||
Accretion of asset retirement obligations | 19,437 | 38,973 | 64,690 | ||||||||||
Impairment of oil and natural gas properties | 86,820 | 86,820 | 2,813,570 | ||||||||||
General and administrative expense | 15,435 | 27,557 | 102,736 | ||||||||||
Total Costs and Expenses | 236,348 | 377,705 | 3,723,952 | ||||||||||
Operating Loss | 11,708 | (93,737) | (82,029) | (3,017,425) | |||||||||
Other (Expense) Income | |||||||||||||
Loss from equity method investees | (10,746) | ||||||||||||
Other income, net | 62 | 117 | 3,596 | ||||||||||
Gains (Losses) on Extinguishment of Debt | 1,525,596 | ||||||||||||
Interest expense | (4,838) | (12,580) | (405,658) | ||||||||||
Total Other (Expense) Income, net | (4,776) | (12,463) | 1,112,788 | ||||||||||
Loss Before Reorganization Items and Income Taxes | (98,513) | (94,492) | (1,904,637) | ||||||||||
Reorganization items | (32,633) | 2,748,395 | (14,201) | ||||||||||
(Loss) Income Before Income Taxes | (131,146) | 2,653,903 | (1,918,838) | ||||||||||
Income Tax Benefit | (87) | ||||||||||||
Net (Loss) Income | $ 2,785,049 | $ (131,146) | $ 2,653,903 | (1,918,751) | |||||||||
Preferred Stock Dividends | 8,394 | ||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ (1,927,145) | ||||||||||||
(Loss) Earnings per Share | |||||||||||||
Basic (in dollars per share) | $ 28.17 | $ 26.99 | |||||||||||
Diluted (in dollars per share) | $ 26.58 | $ 25.33 | |||||||||||
Basic and Diluted (in dollars per share) | $ (1.34) | $ (20.11) | |||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic (in shares) | 98,850 | 98,337 | |||||||||||
Diluted (in shares) | 104,787 | 104,787 | |||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 | |||||||||||
Adjustment | |||||||||||||
Revenues | |||||||||||||
Oil sales | $ (1,294) | $ 304 | $ 172 | $ 476 | $ (818) | ||||||||
Total Revenues | (1,294) | 304 | 172 | 476 | (818) | ||||||||
Costs and Expenses | |||||||||||||
Lease operating | (1,681) | 2,110 | 429 | 429 | |||||||||
Depreciation, depletion and amortization | 65 | 24 | (110) | (86) | (21) | ||||||||
Accretion of asset retirement obligations | (139) | (66) | 684 | 618 | 479 | ||||||||
Impairment of oil and natural gas properties | 2,357 | 848 | (3,280) | (2,432) | (75) | ||||||||
Total Costs and Expenses | 2,283 | 2,898 | (596) | 2,302 | 4,585 | ||||||||
Operating Loss | (3,577) | (2,594) | 768 | (1,826) | (5,403) | ||||||||
Other (Expense) Income | |||||||||||||
(Loss) Income Before Income Taxes | (3,577) | (2,594) | 768 | (1,826) | (5,403) | ||||||||
Net (Loss) Income | $ (3,577) | $ (2,594) | $ 768 | $ (1,826) | $ (5,403) | ||||||||
(Loss) Earnings per Share | |||||||||||||
Basic and Diluted (in dollars per share) | $ (0.11) | $ (0.08) | $ 0.02 | $ (0.05) | $ (0.16) | ||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | ||||||||
Adjustment | Predecessor | |||||||||||||
Revenues | |||||||||||||
Oil sales | $ 352 | $ 1,010 | $ 591 | ||||||||||
Total Revenues | $ 658 | 352 | 1,010 | 591 | |||||||||
Costs and Expenses | |||||||||||||
Lease operating | (429) | ||||||||||||
Depreciation, depletion and amortization | (432) | (424) | 23 | ||||||||||
Accretion of asset retirement obligations | (362) | (593) | 18 | ||||||||||
Impairment of oil and natural gas properties | (9,262) | (9,039) | 458 | ||||||||||
Total Costs and Expenses | (10,056) | (10,485) | 499 | ||||||||||
Operating Loss | 1,087 | 10,408 | 11,495 | 92 | |||||||||
Other (Expense) Income | |||||||||||||
Loss Before Reorganization Items and Income Taxes | 10,408 | 11,495 | 92 | ||||||||||
Reorganization items | (14,787) | ||||||||||||
(Loss) Income Before Income Taxes | 10,408 | (3,292) | 92 | ||||||||||
Net (Loss) Income | $ (13,700) | $ 10,408 | $ (3,292) | 92 | |||||||||
Preferred Stock Dividends | (3,200) | ||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ 3,292 | ||||||||||||
(Loss) Earnings per Share | |||||||||||||
Basic (in dollars per share) | $ (0.14) | $ (0.04) | |||||||||||
Diluted (in dollars per share) | $ (0.13) | $ (0.03) | |||||||||||
Basic and Diluted (in dollars per share) | $ 0.11 | $ 0.03 | |||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||
Basic (in shares) | 98,850 | 98,337 | |||||||||||
Diluted (in shares) | 104,787 | 104,787 | |||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 |
Revision of Prior Period Fina55
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revision of Prior Period Cash Flow (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Sep. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 |
Cash Flows From Operating Activities | ||||||||||||
Net (loss) income | $ (406,275) | $ (341,010) | ||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | $ 36,131 | $ 38,685 | $ 41,896 | $ 80,581 | $ 116,712 | 150,151 | ||||||
Impairment of oil and natural gas properties | 406,275 | $ 145,100 | 40,774 | 40,774 | 40,774 | 185,860 | $ 406,300 | |||||
Change in fair value of derivative financial instruments | 32,567 | |||||||||||
Accretion of asset retirement obligations | 9,753 | 9,984 | 13,081 | 23,065 | 32,818 | 42,780 | ||||||
Amortization and write-off of debt issuance costs, payment of interest in kind and other | 17 | |||||||||||
Deferred rent | 7,891 | |||||||||||
Provision for loss on accounts receivable | 600 | |||||||||||
Stock-based compensation | 9,486 | |||||||||||
Changes in operating assets and liabilities | ||||||||||||
Accounts receivable | 17,274 | |||||||||||
Prepaid expenses and other assets | 5,167 | |||||||||||
Change in restricted cash | 25,817 | |||||||||||
Settlement of asset retirement obligations | (55,820) | |||||||||||
Accounts payable and accrued liabilities | (35,142) | |||||||||||
Net Cash Provided by (Used in) Operating Activities | 45,638 | |||||||||||
Cash Flows from Investing Activities | ||||||||||||
Capital expenditures | (59,223) | |||||||||||
Insurance payments received | 41 | |||||||||||
Proceeds from the sale of properties | 4,119 | |||||||||||
Net Cash (Used in) Provided by Investing Activities | (55,063) | |||||||||||
Cash Flows from Financing Activities | ||||||||||||
Payments on long-term debt | (4,153) | |||||||||||
Debt issuance costs | (61) | |||||||||||
Net Cash (Used in) Provided by Financing Activities | (4,214) | |||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (13,639) | |||||||||||
Cash and Cash Equivalents, beginning of period | 165,368 | 165,368 | 165,368 | 165,368 | ||||||||
Cash and Cash Equivalents, end of period | 165,368 | $ 151,729 | $ 165,368 | 151,729 | 165,368 | |||||||
As reported | ||||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | 36,066 | 38,661 | 42,006 | 80,667 | 116,733 | |||||||
Impairment of oil and natural gas properties | (2,357) | (848) | 44,054 | 43,206 | 40,849 | |||||||
Accretion of asset retirement obligations | 9,892 | 10,050 | 12,397 | 22,447 | 32,339 | |||||||
Cash Flows from Financing Activities | ||||||||||||
Cash and Cash Equivalents, beginning of period | 165,368 | 165,368 | 165,368 | 165,368 | ||||||||
Cash and Cash Equivalents, end of period | 165,368 | 165,368 | 165,368 | |||||||||
Adjustment | ||||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | 65 | 24 | (110) | (86) | (21) | |||||||
Impairment of oil and natural gas properties | 2,357 | 848 | (3,280) | (2,432) | (75) | |||||||
Accretion of asset retirement obligations | $ (139) | $ (66) | 684 | 618 | 479 | |||||||
Predecessor | ||||||||||||
Cash Flows From Operating Activities | ||||||||||||
Net (loss) income | 2,650,611 | $ (1,918,659) | ||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | $ 31,141 | 60,202 | 339,539 | |||||||||
Impairment of oil and natural gas properties | 77,558 | 77,781 | 2,814,028 | |||||||||
Change in fair value of derivative financial instruments | 19,163 | |||||||||||
Accretion of asset retirement obligations | 19,075 | 38,380 | 64,708 | |||||||||
Loss from equity method investees | 10,746 | |||||||||||
Gain on early extinguishment of debt | (1,525,596) | |||||||||||
Reorganization items | (2,824,176) | |||||||||||
Amortization and write-off of debt issuance costs, payment of interest in kind and other | 5,025 | 138,473 | ||||||||||
Deferred rent | 3,355 | 9,154 | ||||||||||
Provision for loss on accounts receivable | 3,200 | |||||||||||
Stock-based compensation | 183 | 1,336 | ||||||||||
Changes in operating assets and liabilities | ||||||||||||
Accounts receivable | (17,555) | 42,151 | ||||||||||
Prepaid expenses and other assets | (7,425) | (24,438) | ||||||||||
Change in restricted cash | (25,157) | |||||||||||
Settlement of asset retirement obligations | (18,852) | (78,273) | ||||||||||
Accounts payable and accrued liabilities | 40,155 | (62,187) | ||||||||||
Net Cash Provided by (Used in) Operating Activities | (17,473) | (166,655) | ||||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisitions, net of cash | (2,797) | |||||||||||
Capital expenditures | (20,237) | (111,884) | ||||||||||
Insurance payments received | 8,251 | |||||||||||
Change in restricted cash | 31,748 | (22,136) | ||||||||||
Proceeds from the sale of properties | 5,693 | |||||||||||
Other | 195 | (40) | ||||||||||
Net Cash (Used in) Provided by Investing Activities | 11,706 | (122,913) | ||||||||||
Cash Flows from Financing Activities | ||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 334 | |||||||||||
Dividends to shareholders - preferred | (5,673) | |||||||||||
Proceeds from long-term debt | 1,121 | |||||||||||
Payments on long-term debt | (32,088) | (227,884) | ||||||||||
Payment of debt assumed in acquisition | (25,187) | |||||||||||
Fees related to debt extinguishment | (3,526) | |||||||||||
Debt issuance costs | (2,163) | |||||||||||
Other | (35) | (1,044) | ||||||||||
Net Cash (Used in) Provided by Financing Activities | (32,123) | (264,022) | ||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (37,890) | (553,590) | ||||||||||
Cash and Cash Equivalents, beginning of period | 165,368 | 203,258 | 165,368 | 203,258 | 165,368 | 165,368 | 756,848 | |||||
Cash and Cash Equivalents, end of period | 165,368 | 165,368 | 165,368 | 203,258 | ||||||||
Predecessor | As reported | ||||||||||||
Cash Flows From Operating Activities | ||||||||||||
Net (loss) income | 2,653,903 | (1,918,751) | ||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | 31,573 | 60,626 | 339,516 | |||||||||
Impairment of oil and natural gas properties | 86,820 | 86,820 | 2,813,570 | |||||||||
Change in fair value of derivative financial instruments | 19,163 | |||||||||||
Accretion of asset retirement obligations | 19,437 | 38,973 | 64,690 | |||||||||
Loss from equity method investees | 10,746 | |||||||||||
Gain on early extinguishment of debt | (1,525,596) | |||||||||||
Reorganization items | (2,838,963) | |||||||||||
Amortization and write-off of debt issuance costs, payment of interest in kind and other | 5,025 | 138,473 | ||||||||||
Deferred rent | 3,355 | 9,154 | ||||||||||
Provision for loss on accounts receivable | 3,200 | |||||||||||
Stock-based compensation | 183 | 1,336 | ||||||||||
Changes in operating assets and liabilities | ||||||||||||
Accounts receivable | (16,545) | 42,742 | ||||||||||
Prepaid expenses and other assets | (7,425) | (24,438) | ||||||||||
Change in restricted cash | (25,157) | |||||||||||
Settlement of asset retirement obligations | (18,852) | (78,273) | ||||||||||
Accounts payable and accrued liabilities | 40,584 | (62,187) | ||||||||||
Net Cash Provided by (Used in) Operating Activities | (17,473) | (166,655) | ||||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisitions, net of cash | (2,797) | |||||||||||
Capital expenditures | (20,237) | (111,884) | ||||||||||
Insurance payments received | 8,251 | |||||||||||
Change in restricted cash | 31,748 | (22,136) | ||||||||||
Proceeds from the sale of properties | 5,693 | |||||||||||
Other | 195 | (40) | ||||||||||
Net Cash (Used in) Provided by Investing Activities | 11,706 | (122,913) | ||||||||||
Cash Flows from Financing Activities | ||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 334 | |||||||||||
Dividends to shareholders - preferred | (5,673) | |||||||||||
Proceeds from long-term debt | 1,121 | |||||||||||
Payments on long-term debt | (32,088) | (227,884) | ||||||||||
Payment of debt assumed in acquisition | (25,187) | |||||||||||
Fees related to debt extinguishment | (3,526) | |||||||||||
Debt issuance costs | (2,163) | |||||||||||
Other | (35) | (1,044) | ||||||||||
Net Cash (Used in) Provided by Financing Activities | (32,123) | (264,022) | ||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (37,890) | (553,590) | ||||||||||
Cash and Cash Equivalents, beginning of period | $ 165,368 | 203,258 | $ 165,368 | 203,258 | $ 165,368 | $ 165,368 | 756,848 | |||||
Cash and Cash Equivalents, end of period | $ 165,368 | 165,368 | $ 165,368 | 203,258 | ||||||||
Predecessor | Adjustment | ||||||||||||
Cash Flows From Operating Activities | ||||||||||||
Net (loss) income | (3,292) | 92 | ||||||||||
Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||||
Depreciation, depletion and amortization | (432) | (424) | 23 | |||||||||
Impairment of oil and natural gas properties | (9,262) | (9,039) | 458 | |||||||||
Accretion of asset retirement obligations | $ (362) | (593) | 18 | |||||||||
Reorganization items | 14,787 | |||||||||||
Changes in operating assets and liabilities | ||||||||||||
Accounts receivable | (1,010) | $ (591) | ||||||||||
Accounts payable and accrued liabilities | $ (429) |
Revision of Prior Period Fina56
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Principles of Consolidation and Reporting (Details) - Predecessor - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | |
Reclassifications | |||
Reclassification from lease operating expense | $ 6.7 | $ 17.9 | $ 13.6 |
Reclassification into gathering and transportation expenses | 6.7 | 17.9 | 13.6 |
Reclassification from gathering and transportation expenses | 21 | 40.7 | 0 |
Reclassification into pipeline facility fee expense | $ 21 | $ 40.7 | $ 0 |
Revision of Prior Period Fina57
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Use of Estimates (Details) - MMBoe | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Use of Estimates | ||||||
Proved reserves (Energy) | 88,199 | 109.4 | 121,937 | |||
Predecessor | ||||||
Use of Estimates | ||||||
Proved reserves (Energy) | 86,564 | 183,496 | 246,198 |
Revision of Prior Period Fina58
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Cash and Cash Equivalents (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Cash and Cash Equivalents | ||
Cash and cash equivalents | $ 151,729 | $ 165,368 |
Money market account | ||
Cash and Cash Equivalents | ||
Cash and cash equivalents | $ 25,100 |
Revision of Prior Period Fina59
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Restricted Cash (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Money market account | ||
Restricted Cash | ||
Restricted cash | $ 6 | $ 6 |
Revision of Prior Period Fina60
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Accounts Receivable (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts Receivable and Allowance for Doubtful Accounts | ||
Allowance for doubtful accounts | $ 0.6 | $ 0 |
Revision of Prior Period Fina61
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Oil and Natural Gas Properties (Details) $ in Thousands | Dec. 31, 2016USD ($)MMBoe | Dec. 31, 2017USD ($)MMBoe | Mar. 31, 2017USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2017USD ($) | Dec. 31, 2016USD ($)MMBoe | Dec. 31, 2015USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($)MMBoe | Dec. 31, 2016USD ($)MMBoe | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($)MMBoe | Jun. 30, 2014MMBoe |
Oil and gas properties | |||||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | $ 40,774 | $ 40,774 | $ 40,774 | $ 185,860 | $ 406,300 | ||||||||||
Proved undeveloped reserves (Energy) | MMBoe | 36,498 | 22,039 | 36,498 | 22,039 | 36,498 | ||||||||||||
Future development costs associated with proved undeveloped reserves | $ 443,200 | $ 356,100 | $ 443,200 | $ 356,100 | $ 443,200 | ||||||||||||
Maximum expected period from properties first recognized as proved undeveloped to being developed | 5 years | ||||||||||||||||
Predecessor | |||||||||||||||||
Oil and gas properties | |||||||||||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | $ 77,781 | $ 2,330,500 | $ 2,814,028 | $ 2,421,884 | ||||||||
Proved undeveloped reserves (Energy) | MMBoe | 58,151 | 96,256 |
Revision of Prior Period Fina62
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Other Property and Equipment (Details) - Other Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Minimum | |
Other Property and Equipment | |
Useful life of properties | 3 years |
Maximum | |
Other Property and Equipment | |
Useful life of properties | 5 years |
Revision of Prior Period Fina63
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Goodwill (Details) - Predecessor - USD ($) $ in Thousands | Dec. 31, 2014 | Jun. 30, 2015 |
Goodwill | ||
Goodwill impairment | $ 329,300 | $ 329,293 |
Goodwill | $ 0 |
Revision of Prior Period Fina64
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - G & A (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
General and Administrative Expense | ||||
Capitalized general and administrative costs related to exploration and development activities | $ 16.4 | |||
Predecessor | ||||
General and Administrative Expense | ||||
Capitalized general and administrative costs related to exploration and development activities | $ 7.8 | $ 17 | $ 49.2 |
Revision of Prior Period Fina65
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 |
Income Taxes | |||
U.S. federal statutory income tax rate (as a percent) | 35.00% | 35.00% | |
Federal statutory tax rate used to calculate provisional effect of the Tax Reform Act in the period of enactment (as a percent) | 21.00% | ||
Decrease in tax-effected deferred tax assets due to 2017 Tax Reform | $ 204,000 | ||
Reduction in valuation allowance due to 2017 Tax Reform | 204,000 | ||
Net effect on income tax expense or benefit due to 2017 Tax Reform | $ 0 | ||
Tax deduction for cost of property due to 2017 Tax Reform (as a percent) | 100.00% | ||
Net operating loss carryovers | $ 339,000 | $ 339,000 | |
Tax basis of asset retirement obligation | 0 | ||
Valuation allowance | $ 167,645 | 306,206 | |
Increase in valuation allowance | $ 224,000 | ||
Forecast | |||
Income Taxes | |||
U.S. federal statutory income tax rate (as a percent) | 21.00% |
Revision of Prior Period Fina66
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Income Taxes Emergence (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 31, 2016 | Sep. 30, 2012 |
Income Taxes | |||||||
Valuation allowance | $ 306,206 | $ 167,645 | |||||
Tax basis of asset retirement obligation | 0 | ||||||
Increase in valuation allowance | 224,000 | ||||||
Predecessor | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | ||||||
Face value | $ 5,500 | ||||||
Percentage of stock cancelled | 100.00% | ||||||
Withholding tax rate (as a percent) | 30.00% | 30.00% | |||||
Valuation allowance | $ 1,029,300 | $ 1,029,300 | $ 379,300 | ||||
Additional tax basis | $ 633,000 | ||||||
Increase in amount related to the change in total CODI excluded | 663,000 | ||||||
Change in estimates of tax attributes | $ 30,000 | ||||||
Increase in valuation allowance | $ 224,000 | $ 650,000 | $ 356,800 | ||||
4.14% Promissory Note due 2017 | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% | ||||
4.14% Promissory Note due 2017 | Predecessor | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | |||||
Face value | $ 5,500 | $ 5,500 |
Revision of Prior Period Fina67
Revision of Prior Period Financial Statements, Summary of Significant Accounting Policies and Recent Accounting Pronouncements - CODI (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 |
Cancellation of Debt Income | |||
Pre-tax reductions in net operating loss carryovers | $ 681 | ||
Pre-tax reductions in oil and natural gas properties | 915 | ||
Pre-tax reductions in EPL stock basis | 304 | ||
Pre-tax reductions in others | 18 | ||
CODI excluded requiring attribute reduction | $ 1,918 | ||
U.S. federal statutory income tax rate (as a percent) | 35.00% | 35.00% | |
Forecast | |||
Cancellation of Debt Income | |||
U.S. federal statutory income tax rate (as a percent) | 21.00% | ||
As reported | |||
Cancellation of Debt Income | |||
Pre-tax reductions in net operating loss carryovers | $ 486 | ||
Pre-tax reductions in oil and natural gas properties | 1,485 | ||
Pre-tax reductions in EPL stock basis | 543 | ||
Pre-tax reductions in others | 67 | ||
CODI excluded requiring attribute reduction | $ 2,581 |
Chapter 11 Proceedings - Genera
Chapter 11 Proceedings - General (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Mar. 31, 2017 | Jun. 30, 2017 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 06, 2017 | Dec. 30, 2016 |
Chapter 11 Proceedings | |||||||||
Maximum percentage of voting shares received | 50.00% | ||||||||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | $ 40,774 | $ 40,774 | $ 40,774 | $ 185,860 | $ 406,300 |
Chapter 11 Proceedings - Prepet
Chapter 11 Proceedings - Prepetition Revolving Credit Facilty and Exit Facility (Details) $ in Thousands | Mar. 03, 2017 | Dec. 30, 2016USD ($)item | Dec. 31, 2017USD ($) | Mar. 13, 2017USD ($) |
Chapter 11 Proceedings | ||||
Long term debt | $ 74,017 | |||
Exit Facility | ||||
Chapter 11 Proceedings | ||||
Debt instrument term | 3 years | |||
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt | 90.00% | 90.00% | ||
Number of facilities | item | 2 | |||
Letters of credit outstanding | 202,600 | |||
Exit Term Loan | ||||
Chapter 11 Proceedings | ||||
Long term debt | $ 74,000 | |||
Exit Revolving Facility | ||||
Chapter 11 Proceedings | ||||
Maximum borrowing capacity | 227,800 | |||
Letters of credit outstanding | $ 225,000 | $ 200,000 | $ 200,000 |
Chapter 11 Proceedings - Equity
Chapter 11 Proceedings - Equity Interests and Warrant Agreement (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Chapter 11 Proceedings | ||||||
Assets | $ 1,480,707 | $ 1,076,982 | $ 1,480,707 | |||
Shares issued (as a percent) | 100.00% | |||||
Holders of EGC Unsecured Notes and EPL Unsecured Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of warrants issued (in shares) | 2,119,889 | 2,119,889 | ||||
Holders of EGC Unsecured Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of warrants issued (in shares) | 1,271,933 | 1,271,933 | 1,271,933 | |||
Holders of EPL Unsecured Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of warrants issued (in shares) | 847,956 | 847,956 | ||||
Predecessor | ||||||
Chapter 11 Proceedings | ||||||
Assets | $ 0 | $ 0 | ||||
Amount of payments made to shareholders | $ 0 | |||||
Debt instrument, stated interest rate (as a percent) | 4.14% | |||||
Predecessor | 8.25% Senior Notes due 2018 | ||||||
Chapter 11 Proceedings | ||||||
Debt instrument, stated interest rate (as a percent) | 8.25% | 8.25% | 8.25% | 8.25% | ||
Common Stock | ||||||
Chapter 11 Proceedings | ||||||
Number of shares issued | 33,212,000 | 43,000 | ||||
Common Stock | Holders of Second Lien Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of shares issued | 27,897,739 | 27,897,739 | ||||
Common Stock | Holders of EGC Unsecured Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of shares issued | 3,985,391 | 3,985,391 | ||||
Common Stock | Holders of EPL Unsecured Notes | ||||||
Chapter 11 Proceedings | ||||||
Number of shares issued | 1,328,464 | 1,328,464 | ||||
Common Stock | Predecessor | ||||||
Chapter 11 Proceedings | ||||||
Number of shares issued | 3,146,000 | 3,181,000 | 923,000 |
Chapter 11 Proceedings - Amendm
Chapter 11 Proceedings - Amendments to Articles of Incorporation or Bylaws (Details) - $ / shares | Dec. 31, 2017 | Jan. 06, 2017 | Dec. 31, 2016 | Dec. 30, 2016 |
Amendments to Articles of Incorporation or Bylaws | ||||
Capital stock, shares authorized | 110,000,000 | 110,000,000 | ||
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | |
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 | |
Preferred stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Chapter 11 Proceedings - Intere
Chapter 11 Proceedings - Interest Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 9 Months Ended |
Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | |
Predecessor | |||
Chapter 11 Proceedings | |||
Interest on liabilities subject to compromise | $ 52.8 | $ 123.7 | $ 176.5 |
Chapter 11 Proceedings - Potent
Chapter 11 Proceedings - Potential Claims (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Jun. 17, 2017 |
Litigation claim to be paid at pro rata share | ||
Chapter 11 Proceedings | ||
General unsecured claims, accrual | $ 1.5 | $ 1.5 |
Fresh Start Accounting - Genera
Fresh Start Accounting - General (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Dec. 31, 2016 |
Fresh Start Accounting | ||
Maximum percentage of voting shares received | 50.00% | |
Enterprise Value | $ 815,119 | |
Proved location drilling period | 5 years | |
Forward price period | 4 years | |
Inflation adjustment period | 4 years | |
Cost of capital (as a percent) | 11.10% | |
Proved reserves | $ 1,127,600 | |
Probable reserves | 295,300 | |
Possible reserves | $ 80,800 | |
Minimum | ||
Fresh Start Accounting | ||
Enterprise Value | $ 600,000 | |
Maximum | ||
Fresh Start Accounting | ||
Maximum percentage of voting shares received | 50.00% | |
Enterprise Value | 900,000 | |
Weighted average | ||
Fresh Start Accounting | ||
Enterprise Value | $ 815,100 | |
Cost of capital (as a percent) | 11.10% |
Fresh Start Accounting - Reconc
Fresh Start Accounting - Reconciliation of enterprise value to estimated fair value of Successor (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Reorganization | |||||
Enterprise Value | $ 815,119 | ||||
Add: Cash and cash equivalents | $ 151,729 | 165,368 | |||
Less: Fair value of debt | (78,497) | ||||
Fair Value of Successor common stock and warrants | 901,990 | ||||
Less: Fair value of warrants | (8,056) | ||||
Fair Value of Successor common stock | 893,934 | ||||
Predecessor Company before Reorganization and Fresh-Start Adjustments | |||||
Reorganization | |||||
Add: Cash and cash equivalents | 164,817 | ||||
Predecessor | |||||
Reorganization | |||||
Add: Cash and cash equivalents | 165,368 | $ 203,258 | $ 756,848 | $ 145,806 | |
Fair Value of Successor common stock and warrants | $ 901,990 |
Fresh Start Accounting - Exit F
Fresh Start Accounting - Exit Facility and Warrants (Details) $ / shares in Units, $ in Thousands | Mar. 03, 2017 | Dec. 30, 2016USD ($)item$ / sharesshares | Dec. 31, 2016shares | Dec. 31, 2017USD ($) |
Credit facility | ||||
Long term debt | $ | $ 74,017 | |||
Exit Facility | ||||
Credit facility | ||||
Debt instrument term | 3 years | |||
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt | 90.00% | 90.00% | ||
Number of facilities | item | 2 | |||
Exit Term Loan | ||||
Credit facility | ||||
Long term debt | $ | $ 74,000 | |||
Holders of EGC Unsecured Notes and EPL Unsecured Notes | ||||
Warrants | ||||
Number of warrants issued (in shares) | shares | 2,119,889 | 2,119,889 | ||
Number of shares issued upon exercise of each warrant | shares | 1 | |||
Exercise price of warrant (in dollars per share) | $ / shares | $ 43.66 | |||
Minimum percentage increase or decrease in the exercise price resulting from cumulative adjustments to the applicable exercise price | 1.00% | |||
Fair value of warrant (in dollars per warrant) | $ / shares | $ 3.80 |
Fresh Start Accounting - Reco77
Fresh Start Accounting - Reconciliation of enterprise value to estimated reorganization of Successor (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Reorganization | |||||
Enterprise Value | $ 815,119 | ||||
Add: Cash and cash equivalents | $ 151,729 | 165,368 | |||
Add: Other working capital liabilities | 156,792 | ||||
Add: Other long-term liabilities | 10,783 | 12,595 | |||
Add: Asset retirement obligation | $ 664,851 | 737,108 | |||
Reorganization value of Successor assets | 1,886,982 | ||||
Predecessor Company before Reorganization and Fresh-Start Adjustments | |||||
Reorganization | |||||
Add: Cash and cash equivalents | 164,817 | ||||
Add: Other long-term liabilities | 22,776 | ||||
Predecessor | |||||
Reorganization | |||||
Add: Cash and cash equivalents | 165,368 | $ 203,258 | $ 756,848 | $ 145,806 | |
Add: Asset retirement obligation | $ 551,468 | $ 537,637 |
Fresh Start Accounting - Reorga
Fresh Start Accounting - Reorganization and Application of ASC 852 and Impairment (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 30, 2016 | Dec. 31, 2017 | Mar. 31, 2017 | Sep. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Reorganization | ||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | $ 40,774 | $ 40,774 | $ 40,774 | $ 185,860 | $ 406,300 | |||||
Current Assets | ||||||||||||
Cash and cash equivalents | 165,368 | 151,729 | $ 165,368 | 151,729 | 165,368 | |||||||
Accounts receivable, net | ||||||||||||
Oil and natural gas sales | 69,744 | 55,598 | 69,744 | 55,598 | 69,744 | |||||||
Joint interest billings | 6,029 | 6,336 | 6,029 | 6,336 | 6,029 | |||||||
Other Receivables, Net, Current | 17,944 | 15,726 | 17,944 | 15,726 | 17,944 | |||||||
Prepaid expenses and other current assets | 17,980 | 21,602 | 17,980 | 21,602 | 17,980 | |||||||
Restricted cash | 32,337 | 6,392 | 32,337 | 6,392 | 32,337 | |||||||
Total Current Assets | 309,402 | 257,383 | 309,402 | 257,383 | 309,402 | |||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | 1,097,471 | 764,922 | 1,097,471 | 764,922 | 1,097,471 | |||||||
Other property and equipment, net | 20,007 | 10,120 | 20,007 | 10,120 | 20,007 | |||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 1,117,478 | 775,042 | 1,117,478 | 775,042 | 1,117,478 | |||||||
Other Assets | ||||||||||||
Restricted Cash and Cash Equivalents, Noncurrent | 25,583 | 25,712 | 25,583 | 25,712 | 25,583 | |||||||
Other Assets, Miscellaneous, Noncurrent | 28,244 | 18,845 | 28,244 | 18,845 | 28,244 | |||||||
Total Other Assets | 53,827 | 44,557 | 53,827 | 44,557 | 53,827 | |||||||
Total Assets | 1,480,707 | 1,076,982 | 1,480,707 | 1,076,982 | 1,480,707 | |||||||
Current Liabilities | ||||||||||||
Accounts payable | 101,117 | 85,122 | 101,117 | 85,122 | 101,117 | |||||||
Accrued liabilities | 55,675 | 45,494 | 55,675 | 45,494 | 55,675 | |||||||
Asset retirement obligations | 56,601 | 51,398 | 56,601 | 51,398 | 56,601 | |||||||
Less: current maturities | 4,268 | 21 | 4,268 | 21 | 4,268 | |||||||
Total Current Liabilities | 217,661 | 214,602 | 217,661 | 214,602 | 217,661 | |||||||
Long-term debt, less current maturities | 74,229 | 73,952 | 74,229 | 73,952 | 74,229 | |||||||
Asset retirement obligations | 680,507 | 613,453 | 680,507 | 613,453 | 680,507 | |||||||
Other liabilities | 12,595 | 10,783 | 12,595 | 10,783 | 12,595 | |||||||
Liabilities Not Subject to Compromise | 984,992 | 984,992 | 984,992 | |||||||||
Total Liabilities | 984,992 | 912,790 | 984,992 | 912,790 | 984,992 | |||||||
Stockholders' Equity | ||||||||||||
Common stock | 332 | 333 | 332 | 333 | 332 | |||||||
Additional paid-in capital | 901,658 | 911,144 | 901,658 | 911,144 | 901,658 | |||||||
Accumulated deficit | (406,275) | (747,285) | (406,275) | (747,285) | (406,275) | |||||||
Total Stockholders' Equity | 495,715 | 164,192 | 495,715 | 164,192 | 495,715 | |||||||
Total Liabilities and Stockholders' Equity | 1,480,707 | $ 1,076,982 | 1,480,707 | $ 1,076,982 | 1,480,707 | |||||||
Predecessor | ||||||||||||
Reorganization | ||||||||||||
Impairment of oil and natural gas properties | $ 77,558 | 77,781 | $ 2,814,028 | |||||||||
Current Assets | ||||||||||||
Cash and cash equivalents | 165,368 | 165,368 | 165,368 | $ 203,258 | $ 756,848 | |||||||
Successor Company before Impairment | ||||||||||||
Current Assets | ||||||||||||
Cash and cash equivalents | 165,368 | 165,368 | 165,368 | |||||||||
Accounts receivable, net | ||||||||||||
Oil and natural gas sales | 69,744 | 69,744 | 69,744 | |||||||||
Joint interest billings | 6,029 | 6,029 | 6,029 | |||||||||
Other Receivables, Net, Current | 17,944 | 17,944 | 17,944 | |||||||||
Prepaid expenses and other current assets | 17,980 | 17,980 | 17,980 | |||||||||
Restricted cash | 32,337 | 32,337 | 32,337 | |||||||||
Total Current Assets | 309,402 | 309,402 | 309,402 | |||||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | 1,503,746 | 1,503,746 | 1,503,746 | |||||||||
Other property and equipment, net | 20,007 | 20,007 | 20,007 | |||||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 1,523,753 | 1,523,753 | 1,523,753 | |||||||||
Other Assets | ||||||||||||
Restricted Cash and Cash Equivalents, Noncurrent | 25,583 | 25,583 | 25,583 | |||||||||
Other Assets, Miscellaneous, Noncurrent | 28,244 | 28,244 | 28,244 | |||||||||
Total Other Assets | 53,827 | 53,827 | 53,827 | |||||||||
Total Assets | 1,886,982 | 1,886,982 | 1,886,982 | |||||||||
Current Liabilities | ||||||||||||
Accounts payable | 101,117 | 101,117 | 101,117 | |||||||||
Accrued liabilities | 55,675 | 55,675 | 55,675 | |||||||||
Asset retirement obligations | 56,601 | 56,601 | 56,601 | |||||||||
Less: current maturities | 4,268 | 4,268 | 4,268 | |||||||||
Total Current Liabilities | 217,661 | 217,661 | 217,661 | |||||||||
Long-term debt, less current maturities | 74,229 | 74,229 | 74,229 | |||||||||
Asset retirement obligations | 680,507 | 680,507 | 680,507 | |||||||||
Other liabilities | 12,595 | 12,595 | 12,595 | |||||||||
Liabilities Not Subject to Compromise | 984,992 | 984,992 | 984,992 | |||||||||
Total Liabilities | 984,992 | 984,992 | 984,992 | |||||||||
Stockholders' Equity | ||||||||||||
Common stock | 332 | 332 | 332 | |||||||||
Additional paid-in capital | 901,658 | 901,658 | 901,658 | |||||||||
Total Stockholders' Equity | 901,990 | 901,990 | 901,990 | |||||||||
Total Liabilities and Stockholders' Equity | 1,886,982 | 1,886,982 | 1,886,982 | |||||||||
Predecessor Company before Reorganization and Fresh-Start Adjustments | ||||||||||||
Current Assets | ||||||||||||
Cash and cash equivalents | 164,817 | 164,817 | 164,817 | |||||||||
Accounts receivable, net | ||||||||||||
Oil and natural gas sales | 69,744 | 69,744 | 69,744 | |||||||||
Joint interest billings | 6,029 | 6,029 | 6,029 | |||||||||
Other Receivables, Net, Current | 18,909 | 18,909 | 18,909 | |||||||||
Prepaid expenses and other current assets | 46,123 | 46,123 | 46,123 | |||||||||
Restricted cash | 32,888 | 32,888 | 32,888 | |||||||||
Total Current Assets | 338,510 | 338,510 | 338,510 | |||||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | 491,521 | 491,521 | 491,521 | |||||||||
Other property and equipment, net | 15,049 | 15,049 | 15,049 | |||||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 506,570 | 506,570 | 506,570 | |||||||||
Other Assets | ||||||||||||
Restricted Cash and Cash Equivalents, Noncurrent | 25,583 | 25,583 | 25,583 | |||||||||
Other Assets, Miscellaneous, Noncurrent | 30,174 | 30,174 | 30,174 | |||||||||
Total Other Assets | 55,757 | 55,757 | 55,757 | |||||||||
Total Assets | 900,837 | 900,837 | 900,837 | |||||||||
Current Liabilities | ||||||||||||
Accounts payable | 67,876 | 67,876 | 67,876 | |||||||||
Accrued liabilities | 40,517 | 40,517 | 40,517 | |||||||||
Asset retirement obligations | 58,537 | 58,537 | 58,537 | |||||||||
Less: current maturities | 74,046 | 74,046 | 74,046 | |||||||||
Total Current Liabilities | 240,976 | 240,976 | 240,976 | |||||||||
Asset retirement obligations | 492,931 | 492,931 | 492,931 | |||||||||
Other liabilities | 22,776 | 22,776 | 22,776 | |||||||||
Liabilities Not Subject to Compromise | 756,683 | 756,683 | 756,683 | |||||||||
Liabilities subject to compromise | 2,931,419 | 2,931,419 | 2,931,419 | |||||||||
Total Liabilities | 3,688,102 | 3,688,102 | 3,688,102 | |||||||||
Stockholders' Equity | ||||||||||||
Accumulated deficit | (4,633,620) | (4,633,620) | (4,633,620) | |||||||||
Total Stockholders' Equity | (2,787,265) | (2,787,265) | (2,787,265) | |||||||||
Total Liabilities and Stockholders' Equity | 900,837 | 900,837 | 900,837 | |||||||||
Predecessor Company before Reorganization and Fresh-Start Adjustments | Predecessor | ||||||||||||
Stockholders' Equity | ||||||||||||
Common stock | 504 | 504 | 504 | |||||||||
Additional paid-in capital | 1,845,851 | 1,845,851 | 1,845,851 | |||||||||
Reorganization Adjustments | ||||||||||||
Reorganization | ||||||||||||
Impairment of oil and natural gas properties | $ 406,300 | |||||||||||
Average oil and gas price period | 12 months | |||||||||||
Current Assets | ||||||||||||
Cash and cash equivalents | 551 | 551 | 551 | |||||||||
Accounts receivable, net | ||||||||||||
Other Receivables, Net, Current | (965) | (965) | (965) | |||||||||
Prepaid expenses and other current assets | (26,260) | (26,260) | (26,260) | |||||||||
Restricted cash | (551) | (551) | (551) | |||||||||
Total Current Assets | (27,225) | (27,225) | (27,225) | |||||||||
Other Assets | ||||||||||||
Total Assets | (27,225) | (27,225) | (27,225) | |||||||||
Current Liabilities | ||||||||||||
Accounts payable | 33,241 | 33,241 | 33,241 | |||||||||
Accrued liabilities | 15,158 | 15,158 | 15,158 | |||||||||
Less: current maturities | (69,778) | (69,778) | (69,778) | |||||||||
Total Current Liabilities | (21,379) | (21,379) | (21,379) | |||||||||
Long-term debt, less current maturities | 74,229 | 74,229 | 74,229 | |||||||||
Other liabilities | 2,345 | 2,345 | 2,345 | |||||||||
Liabilities Not Subject to Compromise | 55,195 | 55,195 | 55,195 | |||||||||
Liabilities subject to compromise | (2,931,419) | (2,931,419) | (2,931,419) | |||||||||
Total Liabilities | (2,876,224) | (2,876,224) | (2,876,224) | |||||||||
Stockholders' Equity | ||||||||||||
Common stock | 332 | 332 | 332 | |||||||||
Additional paid-in capital | 901,658 | 901,658 | 901,658 | |||||||||
Accumulated deficit | 3,793,364 | 3,793,364 | 3,793,364 | |||||||||
Total Stockholders' Equity | 2,848,999 | 2,848,999 | 2,848,999 | |||||||||
Total Liabilities and Stockholders' Equity | (27,225) | (27,225) | (27,225) | |||||||||
Reorganization Adjustments | Predecessor | ||||||||||||
Stockholders' Equity | ||||||||||||
Common stock | (504) | (504) | (504) | |||||||||
Additional paid-in capital | (1,845,851) | (1,845,851) | (1,845,851) | |||||||||
Fresh-Start Adjustments | ||||||||||||
Accounts receivable, net | ||||||||||||
Prepaid expenses and other current assets | (1,883) | (1,883) | (1,883) | |||||||||
Total Current Assets | (1,883) | (1,883) | (1,883) | |||||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | 1,012,225 | 1,012,225 | 1,012,225 | |||||||||
Other property and equipment, net | 4,958 | 4,958 | 4,958 | |||||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 1,017,183 | 1,017,183 | 1,017,183 | |||||||||
Other Assets | ||||||||||||
Other Assets, Miscellaneous, Noncurrent | (1,930) | (1,930) | (1,930) | |||||||||
Total Other Assets | (1,930) | (1,930) | (1,930) | |||||||||
Total Assets | 1,013,370 | 1,013,370 | 1,013,370 | |||||||||
Current Liabilities | ||||||||||||
Asset retirement obligations | (1,936) | (1,936) | (1,936) | |||||||||
Total Current Liabilities | (1,936) | (1,936) | (1,936) | |||||||||
Asset retirement obligations | 187,576 | 187,576 | 187,576 | |||||||||
Other liabilities | (12,526) | (12,526) | (12,526) | |||||||||
Liabilities Not Subject to Compromise | 173,114 | 173,114 | 173,114 | |||||||||
Total Liabilities | 173,114 | 173,114 | 173,114 | |||||||||
Stockholders' Equity | ||||||||||||
Accumulated deficit | 840,256 | 840,256 | 840,256 | |||||||||
Total Stockholders' Equity | 840,256 | 840,256 | 840,256 | |||||||||
Total Liabilities and Stockholders' Equity | 1,013,370 | 1,013,370 | 1,013,370 | |||||||||
Impairment Adjustment | ||||||||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | (406,275) | (406,275) | (406,275) | |||||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | (406,275) | (406,275) | (406,275) | |||||||||
Other Assets | ||||||||||||
Total Assets | (406,275) | (406,275) | (406,275) | |||||||||
Stockholders' Equity | ||||||||||||
Accumulated deficit | (406,275) | (406,275) | (406,275) | |||||||||
Total Stockholders' Equity | (406,275) | (406,275) | (406,275) | |||||||||
Total Liabilities and Stockholders' Equity | $ (406,275) | $ (406,275) | $ (406,275) |
Fresh Start Accounting - Reor79
Fresh Start Accounting - Reorganization Adjustments - Payments and accruals (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 30, 2016 |
Accounts receivable, net | |||
Other Receivables, Net, Current | $ 15,726 | $ 17,944 | |
Prepaid expenses and other current assets | 21,602 | 17,980 | |
Current Liabilities | |||
Accrued liabilities | $ 45,494 | 55,675 | |
Successor Company before Impairment | |||
Accounts receivable, net | |||
Other Receivables, Net, Current | 17,944 | ||
Prepaid expenses and other current assets | 17,980 | ||
Current Liabilities | |||
Accrued liabilities | 55,675 | ||
Reorganization Adjustments | |||
Accounts receivable, net | |||
Other Receivables, Net, Current | (965) | ||
Prepaid expenses and other current assets | (26,260) | ||
Current Liabilities | |||
Accrued liabilities | 15,158 | ||
Liabilities subject to compromise | (2,931,419) | ||
Reorganization Adjustments, Reinstated claims reclassified | |||
Accounts receivable, net | |||
Other Receivables, Net, Current | (1,000) | ||
Current Liabilities | |||
Accrued liabilities | 2,400 | ||
Liabilities subject to compromise | (3,400) | ||
Support parties of EGC abd EPL Unsecured Noteholders | Reorganization Adjustments, Professional fees | |||
Current Liabilities | |||
Accrued liabilities | 1,700 | ||
Support parties of EGC Unsecured Noteholders | Reorganization Adjustments, Professional fees | |||
Accounts receivable, net | |||
Prepaid expenses and other current assets | (11,200) | ||
Support parties of EPL Unsecured Noteholders | Reorganization Adjustments, Professional fees | |||
Accounts receivable, net | |||
Prepaid expenses and other current assets | (9,600) | ||
EXXI Ltd's 3.0% Senior Convertible Notes Trustee | Reorganization Adjustments, Professional fees | |||
Accounts receivable, net | |||
Prepaid expenses and other current assets | (2,000) | ||
EXXI Ltd's restructuring advisors | Reorganization Adjustments, Professional fees | |||
Current Liabilities | |||
Accrued liabilities | 11,000 | ||
EXXI Ltd's restructuring advisors | Reorganization Adjustments, Success fees | |||
Accounts receivable, net | |||
Prepaid expenses and other current assets | $ (3,500) | ||
4.14% Promissory Note due 2017 | |||
Current Liabilities | |||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% |
Fresh Start Accounting - Reor80
Fresh Start Accounting - Reorganization Adjustments - Liabilities subject to compromise (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 30, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Liabilities Subject to Compromise | |||||||
Fair value of common stocks and warrants issued per the Plan | $ (901,990) | $ (901,990) | $ (901,990) | ||||
4.14% Promissory Note due 2017 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 4.14% | 4.14% | 4.14% | 4.14% | 4.14% | ||
Reorganization Adjustments | |||||||
Liabilities Subject to Compromise | |||||||
Total liabilities subject to compromise | $ (2,931,419) | $ (2,931,419) | $ (2,931,419) | ||||
Gain on settlement of liabilities subject to compromise | 1,983,920 | ||||||
Predecessor | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 4.14% | ||||||
Total debt | 2,763,739 | 2,763,739 | 2,763,739 | ||||
Accounts payable | 37,424 | 37,424 | 37,424 | ||||
Accrued liabilities | 130,256 | 130,256 | 130,256 | ||||
Total liabilities subject to compromise | 2,931,419 | 2,931,419 | 2,931,419 | ||||
Fair value of common stocks and warrants issued per the Plan | (901,990) | (901,990) | (901,990) | ||||
Fair value of reinstated accounts payable and accrued liabilities to be settled in cash | (43,509) | (43,509) | (43,509) | ||||
Cash payment for 3.0% Senior Convertible Notes | (2,000) | ||||||
Gain on settlement of liabilities subject to compromise | $ 1,983,920 | $ 1,983,900 | $ 1,983,920 | ||||
Predecessor | 11.0% Senior Secured Second Lien Notes due 2020 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 11.00% | 11.00% | 11.00% | 11.00% | 11.00% | ||
Total debt | $ 1,450,000 | $ 1,450,000 | $ 1,450,000 | ||||
Predecessor | 8.25% Senior Notes due 2018 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 8.25% | 8.25% | 8.25% | 8.25% | 8.25% | ||
Total debt | $ 213,677 | $ 213,677 | $ 213,677 | ||||
Predecessor | 6.875% Senior Notes due 2024 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 6.875% | 6.875% | 6.875% | 6.875% | 6.875% | ||
Total debt | $ 143,993 | $ 143,993 | $ 143,993 | ||||
Predecessor | 3.0% Senior Convertible Notes due 2018 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 3.00% | 3.00% | 3.00% | 3.00% | 3.00% | ||
Total debt | $ 363,018 | $ 363,018 | $ 363,018 | ||||
Predecessor | 7.50% Senior Notes due 2021 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 7.50% | 7.50% | 7.50% | 7.50% | 7.50% | ||
Total debt | $ 238,071 | $ 238,071 | $ 238,071 | ||||
Predecessor | 7.75% Senior Notes due 2019 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 7.75% | 7.75% | 7.75% | 7.75% | 7.75% | ||
Total debt | $ 101,077 | $ 101,077 | $ 101,077 | ||||
Predecessor | 9.25 Percent Senior Notes due 2017 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 9.25% | 9.25% | 9.25% | 9.25% | 9.25% | ||
Total debt | $ 249,452 | $ 249,452 | $ 249,452 | ||||
Predecessor | 4.14% Promissory Note due 2017 | |||||||
Liabilities Subject to Compromise | |||||||
Rate of interest on notes payable | 4.14% | 4.14% | 4.14% | 4.14% | |||
Total debt | $ 4,001 | $ 4,001 | $ 4,001 | ||||
Predecessor | Capital lease obligations | |||||||
Liabilities Subject to Compromise | |||||||
Total debt | $ 450 | $ 450 | $ 450 |
Fresh Start Accounting - Reor81
Fresh Start Accounting - Reorganization Adjustments - Equity issuance (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2016 |
Stockholders' Equity | |||
Fair value of warrants | $ 8,056 | $ 8,056 | |
Reorganization Adjustments | |||
Stockholders' Equity | |||
Number of shares issued | 33,211,594 | ||
Holders of EGC Unsecured Notes and EPL Unsecured Notes | |||
Stockholders' Equity | |||
Number of warrants issued (in shares) | 2,119,889 | 2,119,889 | |
Exercise price of warrant (in dollars per share) | $ 43.66 | ||
Fair value of warrants (in dollars per share) | $ 3.80 | $ 3.80 | |
Fair value of warrants | $ 8,100 | $ 8,100 | |
Holders of Second Lien Notes | Reorganization Adjustments | |||
Stockholders' Equity | |||
Number of shares issued | 27,897,739 | ||
Holders of EGC Unsecured Notes | |||
Stockholders' Equity | |||
Number of warrants issued (in shares) | 1,271,933 | 1,271,933 | 1,271,933 |
Holders of EGC Unsecured Notes | Reorganization Adjustments | |||
Stockholders' Equity | |||
Number of shares issued | 3,985,391 | ||
Number of warrants issued (in shares) | 847,956 | ||
Holders of EPL Unsecured Notes | |||
Stockholders' Equity | |||
Number of warrants issued (in shares) | 847,956 | 847,956 | |
Holders of EPL Unsecured Notes | Reorganization Adjustments | |||
Stockholders' Equity | |||
Number of shares issued | 1,328,464 | ||
Number of shares issued upon exercise | 2,119,889 | 2,119,889 | |
Exercise price of warrant (in dollars per share) | $ 43.66 | $ 43.66 |
Fresh Start Accounting - Reor82
Fresh Start Accounting - Reorganization Adjustments - Cumulative impact (Details) - Reorganization Adjustments $ in Thousands | 6 Months Ended |
Dec. 31, 2016USD ($) | |
Reorganization | |
Gain on settlement of liabilities subject to compromise | $ 1,983,920 |
Cancellation of EXXI Ltd equity | 1,846,355 |
Accrual of success fee | (12,651) |
Payments made of plan support parties | (24,260) |
Net impact to accumulated deficit | $ 3,793,364 |
Fresh Start Accounting - Fresh
Fresh Start Accounting - Fresh Start Adjustments (Details) $ in Millions | Dec. 30, 2016 | Dec. 31, 2016USD ($)$ / MMBTU$ / bbl |
Fresh Start Adjustments | ||
Cost of capital (as a percent) | 11.10% | |
Proved location drilling period | 5 years | |
Inflation escalation factor (as a percent) | 2.00% | |
Credit adjusted risk free rate (as a percent) | 6.50% | |
Asset retirement obligation, fair value | $ | $ 737.1 | |
Weighted average | ||
Fresh Start Adjustments | ||
Cost of capital (as a percent) | 11.10% | |
Oil Reserves | Weighted average | ||
Fresh Start Adjustments | ||
Weighted average commodity prices utilized in the determination of fair value | 60.37 | |
Natural Gas Reserves | Weighted average | ||
Fresh Start Adjustments | ||
Weighted average commodity prices utilized in the determination of fair value | $ / MMBTU | 3.02 | |
Natural Gas Liquids | Weighted average | ||
Fresh Start Adjustments | ||
Weighted average commodity prices utilized in the determination of fair value | 25.36 |
Fresh Start Accounting - Reor84
Fresh Start Accounting - Reorganization Items (Details) - Predecessor - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2016 | Sep. 30, 2016 | Dec. 31, 2016 | Jun. 30, 2016 |
Reorganization | |||||
Gain on settlement of liabilities subject to compromise | $ 1,983,920 | $ 1,983,900 | $ 1,983,920 | ||
Fresh start adjustments | 840,300 | 840,256 | |||
Reorganization legal and professional fees and expenses | $ (58,000) | $ (32,600) | (90,568) | $ (14,201) | |
Gain (loss) on reorganization items | $ 2,733,608 | $ (14,201) |
Acquisitions and Dispositions -
Acquisitions and Dispositions - M21K Acquisition (Details) - Predecessor $ in Thousands | Aug. 11, 2015USD ($)$ / MMBTU$ / bbl |
M21K | |
Acquisitions | |
Royalty interest, production proceeds threshold (in dollars per Bbl) | $ / bbl | 65 |
Royalty interest, production proceeds threshold (in dollars per MMBTU) | $ / MMBTU | 3.50 |
Royalty interest, production proceeds period | 4 years |
Royalty interest, production proceeds aggregate amount | $ 20,000 |
Additional payment due (as a percent) | 20.00% |
Asset retirement obligations | $ (66,700) |
Net working capital | (21,301) |
Fair value of debt assumed | (25,187) |
Cash acquired in acquisition included in net working capital | 1,000 |
M21K | Oil and natural gas properties - evaluated | |
Acquisitions | |
Oil and natural gas properties | 73,910 |
M21K | Oil and natural gas properties - unevaluated | |
Acquisitions | |
Oil and natural gas properties | $ 39,278 |
EXXI M21K | |
Acquisitions | |
Percentage of investments under the equity method | 20.00% |
Acquisitions and Dispositions86
Acquisitions and Dispositions - Grand Isle Disposition (Details) - Predecessor - Grand Isle Gathering System - Disposal Group, Not Discontinued Operations $ in Millions | Jun. 30, 2015USD ($) |
Dispositions | |
Cash consideration | $ 245 |
Gain (loss) on disposal | 0 |
Reduction to cost pool related to divestiture | $ 248.9 |
Acquisitions and Dispositions87
Acquisitions and Dispositions - East Bay Field Disposition (Details) $ in Thousands | Jun. 30, 2015USD ($)item | Dec. 31, 2017USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Jul. 01, 2015USD ($) |
Dispositions | |||||
Proceeds from the sale of properties | $ 4,119 | ||||
Predecessor | |||||
Dispositions | |||||
Proceeds from the sale of properties | $ 5,693 | $ 261,931 | |||
Predecessor | East Bay Field | Disposal Group, Not Discontinued Operations | |||||
Dispositions | |||||
Cash consideration | $ 21,000 | 21,000 | $ 20,300 | ||
Amount of asset retirement obligation assumed by acquirer | $ 55,100 | ||||
Number of installments | item | 2 | ||||
Proceeds from the sale of properties | $ 5,000 | ||||
Percentage of overriding royalty interest retained | 5.00% | ||||
Minimum average monthly WTI | $ 65,000 | ||||
Maximum period for retained overriding royalty interest | 5 years | ||||
Maximum receivable amount for overriding royalty interest | $ 7,000 | $ 7,000 | $ 6,400 | ||
Percentage of deep rights retained | 50.00% | ||||
Gain (loss) on disposal | $ 0 | ||||
Reduction to cost pool related to divestiture | $ 68,900 |
Goodwill (Details)
Goodwill (Details) $ in Thousands | Dec. 31, 2014USD ($) | Dec. 31, 2017item | Jun. 30, 2015USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) |
Goodwill | |||||
Number of reporting units | item | 1 | ||||
Predecessor | |||||
Goodwill | |||||
Goodwill impairment | $ 329,300 | $ 329,293 | |||
Goodwill. | 0 | ||||
Goodwill tax basis | 0 | ||||
Income tax benefit from goodwill impairment | $ 0 | ||||
Predecessor | Catering Business | |||||
Goodwill | |||||
Goodwill. | $ 0 | $ 800 |
Property and Equipment - Schedu
Property and Equipment - Schedule (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and gas properties | ||
Proved properties | $ 1,307,009 | $ 1,127,608 |
Less: accumulated depreciation, depletion, amortization and impairment | (742,286) | (406,275) |
Proved properties, net | 564,723 | 721,333 |
Unevaluated properties | 200,199 | 376,138 |
Oil and gas properties, net | 764,922 | 1,097,471 |
Other property and equipment | 13,780 | 20,007 |
Less: accumulated depreciation | (3,660) | |
Other property and equipment, net | 10,120 | 20,007 |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | $ 775,042 | $ 1,117,478 |
Property and Equipment - Additi
Property and Equipment - Additional information (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)MMBoe | Dec. 31, 2016USD ($)MMBoe | |
Property and Equipment | ||
Proved undeveloped reserves (Energy) | MMBoe | 22,039 | 36,498 |
Future development costs associated with proved undeveloped reserves | $ 356.1 | $ 443.2 |
Maximum expected period from properties first recognized as proved undeveloped to being developed | 5 years | |
Reduction in unevaluated properties | $ 175.9 | |
Unevaluated properties costs transferred to evaluated properties | 121.8 | |
Amortization to evaluated properties | $ 54.1 |
Property and Equipment - Impair
Property and Equipment - Impairment (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Mar. 31, 2017 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Impairment | ||||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | $ 40,774 | $ 40,774 | $ 40,774 | $ 185,860 | $ 406,300 | |||||||||
Predecessor | ||||||||||||||||
Impairment | ||||||||||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | $ 77,781 | $ 2,330,500 | $ 2,814,028 | $ 2,421,884 |
Equity Method Investments (Deta
Equity Method Investments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Aug. 11, 2015 | |
M21K | |||
Equity Method Investments | |||
Maximum borrowing capacity | $ 100,000 | ||
Current borrowing base | $ 40,000 | ||
Debt outstanding | $ 28,000 | ||
Letters of credit outstanding | 1,200 | ||
Predecessor | |||
Equity Method Investments | |||
Equity (loss) income | $ (10,746) | (17,165) | |
Predecessor | EXXI M21K | |||
Equity Method Investments | |||
Percentage of investments under the equity method | 20.00% | ||
Equity (loss) income | $ 10,700 | 17,400 | |
Other-than-temporary investment related to investment | $ 11,800 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 30, 2016 |
Long-Term Debt | |||
Total debt | $ 74,017 | $ 78,497 | |
Less: debt issue costs | 44 | ||
Less: current maturities | 21 | 4,268 | |
Total long-term debt | 73,952 | 74,229 | |
Exit Facility | |||
Long-Term Debt | |||
Total debt | $ 73,996 | $ 73,996 | $ 74,000 |
4.14% Promissory Note due 2017 | |||
Long-Term Debt | |||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% |
Total debt | $ 4,001 | ||
Capital lease obligations | |||
Long-Term Debt | |||
Total debt | $ 21 | $ 500 |
Long-Term Debt - Maturities of
Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Twelve Months Ending December 31, | |
2,018 | $ 21 |
2,019 | 73,996 |
Total debt | $ 74,017 |
Long-Term Debt - Exit Facility
Long-Term Debt - Exit Facility (Details) $ in Thousands | Mar. 13, 2017USD ($) | Mar. 03, 2017 | Dec. 30, 2016USD ($)item | Jun. 30, 2018USD ($) | Mar. 31, 2018item | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Long-Term Debt | |||||||
Debt | $ 74,017 | $ 78,497 | |||||
Exit Facility | |||||||
Long-Term Debt | |||||||
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt | 90.00% | 90.00% | |||||
Number of facilities | item | 2 | ||||||
Debt | $ 74,000 | 73,996 | $ 73,996 | ||||
Letters of credit | 202,600 | ||||||
Minimum percentage of revised net present value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages | 90.00% | ||||||
Exit Facility | Plan | |||||||
Long-Term Debt | |||||||
Minimum Current ratio | 1 | ||||||
Maximum Leverage ratio | 4 | ||||||
Leverage ratio, Number of trailing quarters | item | 4 | ||||||
Exit Term Loan | Forecast | |||||||
Long-Term Debt | |||||||
Contingent prepayment of debt during the fiscal quarter ending June 30, 2018 | $ 5,550 | ||||||
Exit Term Loan | Plan | |||||||
Long-Term Debt | |||||||
Asset coverage ratio threshold to make mandatory payment on exit term loan | 1.50 | ||||||
Percentage of aggregate outstanding principal amount to be prepaid if asset coverage ratio is less than threshold | 7.50% | ||||||
Exit Revolving Facility | |||||||
Long-Term Debt | |||||||
Maximum credit capacity | 227,800 | ||||||
Letters of credit | $ 200,000 | $ 225,000 | 200,000 | ||||
Reduction in borrowing capacity as a percentage of reduction in letters of credit | 50.00% | ||||||
Reduction in borrowing capacity | $ 12,500 | ||||||
Amount available for borrowing | 12,500 | ||||||
Maximum available for revolving loans | $ 25,000 | ||||||
Letter of credit, rate of fees accrual | 4.50% | ||||||
Letter of credit, rate of issuance fee per annum | 0.25% | ||||||
Commitment fee (as a percent) | 0.50% | ||||||
Letter of Credit | Exit Revolving Facility | |||||||
Long-Term Debt | |||||||
Reduction in letter of credit | $ 25,000 | ||||||
Base Rate | Exit Term Loan | |||||||
Long-Term Debt | |||||||
Percentage points added to reference rate (as a percent) | 3.50% | ||||||
Base Rate | Exit Revolving Facility | |||||||
Long-Term Debt | |||||||
Percentage points added to reference rate (as a percent) | 3.50% | ||||||
LIBO Rate | Exit Term Loan | |||||||
Long-Term Debt | |||||||
Percentage points added to reference rate (as a percent) | 4.50% | ||||||
LIBO Rate | Exit Revolving Facility | |||||||
Long-Term Debt | |||||||
Percentage points added to reference rate (as a percent) | 4.50% |
Long-Term Debt - Prepetition Fa
Long-Term Debt - Prepetition Facility Terms (Details) - USD ($) $ in Thousands | Oct. 25, 2016 | Dec. 31, 2016 | Dec. 31, 2017 | May 31, 2011 |
Long-Term Debt | ||||
Debt outstanding | $ 74,017 | |||
Predecessor | Prepetition Revolving Credit Facility | ||||
Long-Term Debt | ||||
Maximum borrowing capacity | $ 297,100 | $ 327,200 | ||
Percentage of additional payment of interest in kind | 2.00% | |||
Payment of interest in-kind | $ 4,700 | |||
Repayment of credit facility | 30,100 | |||
Debt outstanding | $ 69,300 | |||
Predecessor | Prepetition Revolving Sub-Facility for EPL | ||||
Long-Term Debt | ||||
Maximum borrowing capacity | $ 99,400 |
Long-Term Debt - Prepetition 97
Long-Term Debt - Prepetition Facility Notes Cancelled (Details) - Predecessor - USD ($) $ in Thousands | Dec. 30, 2016 | Dec. 31, 2016 | Dec. 29, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 4.14% | ||||
Face value | $ 5,500 | ||||
11.0% Senior Secured Second Lien Notes due 2020 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 11.00% | 11.00% | 11.00% | ||
Face value | $ 1,450,000 | ||||
Amount of notes cancelled | 1,450,000 | ||||
8.25% Senior Notes due 2018 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 8.25% | 8.25% | 8.25% | ||
Face value | 510,000 | ||||
Amount of notes cancelled | 510,000 | ||||
6.875% Senior Notes due 2024 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 6.875% | 6.875% | 6.875% | ||
Face value | 650,000 | ||||
Amount of notes cancelled | 650,000 | ||||
3.0% Senior Convertible Notes due 2018 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 3.00% | 3.00% | 3.00% | ||
Face value | 400,000 | ||||
Amount of notes cancelled | 400,000 | ||||
7.50% Senior Notes due 2021 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 7.50% | 7.50% | 7.50% | ||
Face value | 500,000 | ||||
Amount of notes cancelled | 500,000 | ||||
7.75% Senior Notes due 2019 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 7.75% | 7.75% | 7.75% | ||
Face value | 250,000 | ||||
Amount of notes cancelled | 250,000 | ||||
9.25 Percent Senior Notes due 2017 | |||||
Long-Term Debt | |||||
Debt instrument, stated interest rate (as a percent) | 9.25% | 9.25% | 9.25% | ||
Face value | $ 750,000 | ||||
Amount of notes cancelled | $ 750,000 |
Long-Term Debt - Prepetition 98
Long-Term Debt - Prepetition Facility Repurchases (Details) - Predecessor - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
Mar. 31, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Jun. 30, 2016 | Dec. 30, 2016 | Feb. 29, 2016 | Jun. 30, 2015 | |
Repurchases | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | |||||||||||
Total cost of notes repurchased | $ 215,900 | $ 215,900 | ||||||||||
Gain on repurchase of notes | 1,492,400 | |||||||||||
Gain on early extinguishment of debt | $ 777,000 | $ 290,300 | $ 458,300 | $ 748,600 | 1,525,596 | |||||||
Interest on liabilities subject to compromise | 52,800 | $ 123,700 | $ 176,500 | |||||||||
6.875% Senior Notes due 2024 | ||||||||||||
Repurchases | ||||||||||||
Principal amount of notes repurchased | $ 506,000 | $ 506,000 | ||||||||||
Debt instrument, stated interest rate (as a percent) | 6.875% | 6.875% | 6.875% | 6.875% | 6.875% | |||||||
7.50% Senior Notes due 2021 | ||||||||||||
Repurchases | ||||||||||||
Principal amount of notes repurchased | $ 261,900 | $ 261,900 | ||||||||||
Debt instrument, stated interest rate (as a percent) | 7.50% | 7.50% | 7.50% | 7.50% | 7.50% | |||||||
7.75% Senior Notes due 2019 | ||||||||||||
Repurchases | ||||||||||||
Principal amount of notes repurchased | $ 148,900 | $ 148,900 | ||||||||||
Debt instrument, stated interest rate (as a percent) | 7.75% | 7.75% | 7.75% | 7.75% | 7.75% | |||||||
8.25% Senior Notes due 2018 | ||||||||||||
Repurchases | ||||||||||||
Principal amount of notes repurchased | $ 296,300 | $ 296,300 | ||||||||||
Debt instrument, stated interest rate (as a percent) | 8.25% | 8.25% | 8.25% | 8.25% | 8.25% | |||||||
Amount repurchased but not yet cancelled | $ 266,600 | |||||||||||
9.25 Percent Senior Notes due 2017 | ||||||||||||
Repurchases | ||||||||||||
Principal amount of notes repurchased | $ 500,600 | $ 500,600 | ||||||||||
Debt instrument, stated interest rate (as a percent) | 9.25% | 9.25% | 9.25% | 9.25% | 9.25% | |||||||
Amount repurchased but not yet cancelled | $ 471,100 | |||||||||||
3.0% Senior Convertible Notes due 2018 | ||||||||||||
Repurchases | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 3.00% | 3.00% | 3.00% | 3.00% | 3.00% | |||||||
Shares issued in conversion (in dollars) | $ 37,000 | |||||||||||
Gain on early extinguishment of debt | $ 33,200 |
Long-Term Debt - 4.14% Promisso
Long-Term Debt - 4.14% Promissory Note (Details) | Dec. 30, 2016USD ($)payment | Dec. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2012USD ($) |
4.14% Promissory Note due 2017 | ||||
Long-Term Debt | ||||
Monthly payment amount | $ 52,000 | |||
Number of lump-sum payments | payment | 1 | |||
Lump-sum payment at maturity | $ 3,300,000 | |||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% | |
Predecessor | ||||
Long-Term Debt | ||||
Face value of notes | $ 5,500,000 | |||
Debt instrument, stated interest rate (as a percent) | 4.14% | |||
Predecessor | 4.14% Promissory Note due 2017 | ||||
Long-Term Debt | ||||
Face value of notes | $ 5,500,000 | $ 5,500,000 | ||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% |
Long-Term Debt - Derivative Ins
Long-Term Debt - Derivative Instruments Premium Financing (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 31, 2017 |
Long-Term Debt | ||||
Long term debt | $ 74,017 | |||
Predecessor | Derivative Instruments Premium Financing | ||||
Long-Term Debt | ||||
Interest rate (as a percent) | 2.50% | 2.50% | 2.50% | |
Long term debt | $ 0 | $ 0 | $ 10,600 |
Long-Term Debt - Interest Expen
Long-Term Debt - Interest Expense (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 30, 2016 | |
Long-Term Debt | ||||||||||||
Amortization of debt issue cost | $ 17 | |||||||||||
Interest expense | $ 3,653 | $ 3,642 | $ 3,834 | $ 7,476 | $ 11,129 | $ 14,836 | ||||||
Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Interest on liabilities subject to compromise | $ 52,800 | $ 123,700 | $ 176,500 | |||||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | |||||||||||
Amortization of debt issue cost | 5,025 | $ 138,473 | $ 23,247 | |||||||||
Interest expense | 12,580 | 405,658 | 323,308 | |||||||||
Prepetition Revolving Credit Facility | ||||||||||||
Long-Term Debt | ||||||||||||
Interest on liabilities subject to compromise | 123,700 | $ 176,500 | ||||||||||
Prepetition Revolving Credit Facility | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Interest expense | 11,670 | 15,703 | 25,506 | |||||||||
Amortization of debt issue cost | $ 725 | $ 5,185 | $ 12,491 | |||||||||
11.0% Senior Secured Second Lien Notes due 2020 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 11.00% | 11.00% | 11.00% | 11.00% | 11.00% | |||||||
Interest expense | $ 125,852 | $ 48,505 | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | 6,249 | 2,358 | ||||||||||
Amortization of debt issue cost | $ 5,047 | $ 1,887 | ||||||||||
11.0% Senior Secured Second Lien Notes due 2020-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 11.00% | 11.00% | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | $ 44,855 | |||||||||||
Amortization of debt issue cost | $ 36,243 | |||||||||||
8.25% Senior Notes due 2018 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 8.25% | 8.25% | 8.25% | 8.25% | 8.25% | |||||||
Interest expense | $ 27,899 | $ 42,075 | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | $ (8,818) | $ (11,108) | ||||||||||
8.25% Senior Notes due 2018-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 8.25% | 8.25% | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | $ (7,961) | |||||||||||
6.875% Senior Notes due 2024 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 6.875% | 6.875% | 6.875% | 6.875% | 6.875% | |||||||
Interest expense | $ 18,033 | $ 44,701 | ||||||||||
Amortization of debt issue cost | $ 457 | $ 1,127 | ||||||||||
6.875% Senior Notes due 2024-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 6.875% | 6.875% | ||||||||||
Amortization of debt issue cost | $ 1,946 | |||||||||||
3.0% Senior Convertible Notes due 2018 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 3.00% | 3.00% | 3.00% | 3.00% | 3.00% | |||||||
Interest expense | $ 9,340 | $ 12,000 | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | 8,917 | 11,232 | ||||||||||
Amortization of debt issue cost | $ 1,142 | $ 1,439 | ||||||||||
3.0% Senior Convertible Notes due 2018-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 3.00% | 3.00% | ||||||||||
Accretion of original debt issue discount/Amortization of fair value premium | $ 33,370 | |||||||||||
Amortization of debt issue cost | $ 4,271 | |||||||||||
7.50% Senior Notes due 2021 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 7.50% | 7.50% | 7.50% | 7.50% | 7.50% | |||||||
Interest expense | $ 17,414 | $ 37,500 | ||||||||||
Amortization of debt issue cost | $ 478 | $ 1,051 | ||||||||||
7.50% Senior Notes due 2021-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 7.50% | 7.50% | ||||||||||
Amortization of debt issue cost | $ 2,822 | |||||||||||
7.75% Senior Notes due 2019 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 7.75% | 7.75% | 7.75% | 7.75% | 7.75% | |||||||
Interest expense | $ 8,200 | $ 19,375 | ||||||||||
Amortization of debt issue cost | $ 168 | $ 388 | ||||||||||
7.75% Senior Notes due 2019-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 7.75% | 7.75% | ||||||||||
Amortization of debt issue cost | $ 491 | |||||||||||
9.25 Percent Senior Notes due 2017 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 9.25% | 9.25% | 9.25% | 9.25% | 9.25% | |||||||
Interest expense | $ 44,944 | $ 69,375 | ||||||||||
Amortization of debt issue cost | $ 1,902 | 2,358 | ||||||||||
9.25% Senior Notes due 2017-Accelerated | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 9.25% | 9.25% | ||||||||||
Amortization of debt issue cost | $ 913 | |||||||||||
4.14% Promissory Note due 2017 | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% | 4.14% | ||||||||
Interest expense | $ 134 | |||||||||||
4.14% Promissory Note due 2017 | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% | |||||||||
Interest expense | 130 | 192 | ||||||||||
Derivative instruments financing and other | ||||||||||||
Long-Term Debt | ||||||||||||
Interest expense | 525 | |||||||||||
Derivative instruments financing and other | Predecessor | ||||||||||||
Long-Term Debt | ||||||||||||
Interest expense | $ 185 | $ 466 | $ 856 | |||||||||
Exit Term Loan | ||||||||||||
Long-Term Debt | ||||||||||||
Interest expense | 4,050 | |||||||||||
Exit Revolving Facility | ||||||||||||
Long-Term Debt | ||||||||||||
Interest expense | $ 10,127 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Dec. 31, 2016 | Dec. 31, 2017 | |
Beginning of period total | $ 737,108 | |
Liabilities incurred and true-up to liabilities settled | 11,353 | |
Liabilities settled | (55,820) | |
Revisions | (70,570) | |
Accretion expense | 42,780 | |
Fair value fresh start adjustment | $ 185,640 | |
End of period total | 737,108 | 664,851 |
Less: End of period, current portion | 56,601 | 51,398 |
End of period, noncurrent portion | 680,507 | 613,453 |
Predecessor | ||
Beginning of period total | 537,637 | $ 551,468 |
Liabilities incurred and true-up to liabilities settled | 13,880 | |
Liabilities settled | (18,852) | |
Revisions | (19,577) | |
Accretion expense | 38,380 | |
End of period total | $ 551,468 |
Derivative Financial Instrum103
Derivative Financial Instruments - Positions (Details) $ in Millions | Dec. 31, 2017$ / MBblsMBbls | Mar. 15, 2016USD ($) | Dec. 31, 2016contract |
Derivative Financial Instruments | |||
Outstanding derivative contracts | contract | 0 | ||
Swap, Remaining contract term January 2018 to December 2018, NYMEX-WTI | |||
Net open crude oil derivative positions | |||
Volumes (MBbls) | MBbls | 2,920 | ||
Weighted average contract price, Swaps | $ / MBbls | 50.68 | ||
Swap, Remaining contract term January 2018 to June 2018, Argus-LLS | |||
Net open crude oil derivative positions | |||
Volumes (MBbls) | MBbls | 362 | ||
Weighted average contract price, Swaps | $ / MBbls | 55.45 | ||
Swap, Remaining contract term January 2018 to June 2018, ICE Brent | |||
Net open crude oil derivative positions | |||
Volumes (MBbls) | MBbls | 452.5 | ||
Weighted average contract price, Swaps | $ / MBbls | 56.59 | ||
Predecessor | |||
Derivative Financial Instruments | |||
Proceeds from monetization of outstanding crude oil and natural gas | $ | $ 50.6 |
Derivative Financial Instrum104
Derivative Financial Instruments - Fair Values (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Liability Derivative Instruments | |
Gross Commodity Derivative Instruments subject to enforceable master netting agreement | $ 32,567 |
Net amounts presented in Balance Sheets | 32,567 |
Current Liabilities | |
Liability Derivative Instruments | |
Gross Commodity Derivative Instruments subject to enforceable master netting agreement | 32,567 |
Net amounts presented in Balance Sheets | $ 32,567 |
Derivative Financial Instrum105
Derivative Financial Instruments - Gain (loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Jun. 30, 2017 | Sep. 30, 2017 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
(Loss) gain on derivative instruments | ||||||||
Cash settlements | $ (58) | |||||||
Change in fair value | (32,567) | |||||||
Total (loss) gain on derivative financial instruments | $ (12,466) | $ 9,412 | $ 3,698 | $ 13,110 | $ 644 | $ (32,625) | ||
Deposits for collateral with counterparties | $ 0 | $ 0 | ||||||
Predecessor | ||||||||
(Loss) gain on derivative instruments | ||||||||
Cash settlements | $ 59,081 | $ 81,049 | ||||||
Proceeds from monetization | 50,588 | 102,354 | ||||||
Change in fair value | (19,163) | 52,036 | ||||||
Total (loss) gain on derivative financial instruments | $ 90,506 | $ 235,439 |
Stockholders' Equity - Successo
Stockholders' Equity - Successor Common and Preferred Stock (Details) | Dec. 31, 2017item$ / sharesshares | Jan. 06, 2017$ / shares | Dec. 31, 2016$ / sharesshares | Dec. 30, 2016$ / sharesshares |
Amendments to Articles of Incorporation or Bylaws | ||||
Capital stock, shares authorized | 110,000,000 | 110,000,000 | ||
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | |
Common stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 | |
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | |
Number of positions that my be held by same person | item | 2 |
Stockholders' Equity - Registra
Stockholders' Equity - Registration Rights Agreement (Details) - Registration Rights Agreement, February 28, 2017 - shares | Dec. 30, 2016 | Feb. 28, 2017 |
Stockholders' Equity | ||
Ownership threshold (as a percent) | 10.00% | |
Period from Emergence Date | 6 months | |
Shares offered for sale | 9,272,285 | |
Number of shares owned that may be sold | 9,049,929 | |
Shares of common stock on exercise of warrants | 222,356 |
Stockholders' Equity - Warrant
Stockholders' Equity - Warrant Agreement and Shares Issued (Details) - $ / shares | Dec. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Stockholders' Equity | ||||
Common stock, shares outstanding | 33,211,594 | 33,254,963 | 33,211,594 | |
Warrants outstanding (in shares) | 2,119,889 | |||
Holders of EGC Unsecured Notes and EPL Unsecured Notes | ||||
Stockholders' Equity | ||||
Number of warrants issued (in shares) | 2,119,889 | 2,119,889 | ||
Number of shares issued upon exercise of each warrant | 1 | |||
Exercise price of warrant (in dollars per share) | $ 43.66 | |||
Minimum percentage increase or decrease in the exercise price resulting from cumulative adjustments to the applicable exercise price | 1.00% | |||
Holders of EGC Unsecured Notes | ||||
Stockholders' Equity | ||||
Number of warrants issued (in shares) | 1,271,933 | 1,271,933 | 1,271,933 | |
Holders of EPL Unsecured Notes | ||||
Stockholders' Equity | ||||
Number of warrants issued (in shares) | 847,956 | 847,956 | ||
Common Stock | ||||
Stockholders' Equity | ||||
Number of shares issued | 33,212,000 | 43,000 | ||
Common stock, shares outstanding | 33,212,000 | 33,255,000 | 33,212,000 | |
Common Stock | Holders of EGC Unsecured Notes | ||||
Stockholders' Equity | ||||
Number of shares issued | 3,985,391 | 3,985,391 | ||
Common Stock | Holders of EPL Unsecured Notes | ||||
Stockholders' Equity | ||||
Number of shares issued | 1,328,464 | 1,328,464 | ||
Common Stock | Holders of Second Lien Notes | ||||
Stockholders' Equity | ||||
Number of shares issued | 27,897,739 | 27,897,739 |
Stockholders' Equity - Predeces
Stockholders' Equity - Predecessor Common Stock (Details) | May 19, 2016Vote$ / sharesshares | Feb. 24, 2016$ / shares | Dec. 31, 2017$ / sharesshares | Jan. 06, 2017$ / shares | Dec. 31, 2016item$ / sharesshares | Dec. 30, 2016$ / sharesshares |
Stockholders' Equity | ||||||
Common stock, shares authorized | shares | 100,000,000 | 100,000,000 | 100,000,000 | |||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | ||
Predecessor | ||||||
Stockholders' Equity | ||||||
Number of votes per share owned | Vote | 1 | |||||
Common stock, shares authorized | shares | 200,000,000 | |||||
Common stock, par value | $ 0.005 | |||||
Minimum per share requirement under NASDAQ Listing Rule (in dollars per share) | $ 1 | |||||
Number of consecutive days | 30 days | |||||
Number of rights exercised as of balance sheet date | item | 0 |
Stockholders' Equity - Prede110
Stockholders' Equity - Predecessor Preferred Stock (Details) - USD ($) $ in Thousands | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2017 | Dec. 30, 2016 | |
Stockholders' Equity | |||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 | 10,000,000 | |||
Assets | $ 1,480,707 | $ 1,480,707 | $ 1,076,982 | ||||
Predecessor | |||||||
Stockholders' Equity | |||||||
Preferred stock, shares authorized | 7,500,000 | ||||||
Dividends that would have been accrued (in dollars) | 5,700 | ||||||
Assets | $ 0 | 0 | |||||
Dividend payments | $ 0 | ||||||
Preferred Stock | 5.625% Convertible Perpetual Preferred Stock | Predecessor | |||||||
Stockholders' Equity | |||||||
Preferred stock dividend rate (as a percent) | 5.625% | 5.625% | 5.625% | 5.625% | |||
Preferred Stock | 7.25% Convertible Perpetual Preferred Stock | Predecessor | |||||||
Stockholders' Equity | |||||||
Preferred stock dividend rate (as a percent) | 7.25% | 7.25% | 7.25% |
Stockholders' Equity - Conversi
Stockholders' Equity - Conversion of Preferred Stock (Details) - Predecessor - shares | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
5.625% Convertible Perpetual Preferred Stock | ||||
Stockholders' Equity | ||||
Preferred shares converted (in shares) | 300,248 | 150,787 | 1 | |
Common stock shares issued upon conversion of preferred stock (in shares) | 3,145,549 | 1,579,522 | 11 | |
Conversion rate (in shares) | 10.4765 | 10.4765 | 10.2409 | |
7.25% Convertible Perpetual Preferred Stock | ||||
Stockholders' Equity | ||||
Preferred shares converted (in shares) | 5,000 | |||
Common stock shares issued upon conversion of preferred stock (in shares) | 46,472 | |||
Conversion rate (in shares) | 9.2940 | |||
Preferred Stock | 5.625% Convertible Perpetual Preferred Stock | ||||
Stockholders' Equity | ||||
Preferred stock dividend rate (as a percent) | 5.625% | 5.625% | 5.625% | 5.625% |
Preferred Stock | 7.25% Convertible Perpetual Preferred Stock | ||||
Stockholders' Equity | ||||
Preferred stock dividend rate (as a percent) | 7.25% | 7.25% | 7.25% |
Supplemental Cash Flow Infor112
Supplemental Cash Flow Information - Supplemental (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Supplemental Cash Flow Information | ||||
Cash paid for interest | $ 14,867 | |||
Cash paid for income taxes | $ 0 | |||
Predecessor | ||||
Supplemental Cash Flow Information | ||||
Cash paid for interest | $ 7,493 | $ 229,569 | $ 243,238 | |
Cash paid for income taxes | $ 150 | $ 933 |
Supplemental Cash Flow Infor113
Supplemental Cash Flow Information - Non-cash Investing and Financing Activities (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Non-cash investing and financing activities | ||||
Changes in capital expenditures accrued in accounts payable | $ (1,944) | |||
Changes in asset retirement obligations | (59,217) | |||
Changes in other property and equipment | $ (327) | |||
Predecessor | ||||
Non-cash investing and financing activities | ||||
Derivative instruments premium financing | $ 12,025 | |||
Changes in capital expenditures accrued in accounts payable | $ 10,242 | $ (37,151) | (168,569) | |
Acquisition of property against joint interest billings receivable | (1,500) | |||
Inventory transferred to oil and natural gas properties | 7,081 | |||
Changes in asset retirement obligations | $ (5,697) | (2,583) | $ 49,495 | |
Monetization of derivative instruments applied to Revolving Credit Facility | $ 50,588 |
Employee Benefit Plans - Plan (
Employee Benefit Plans - Plan (Details) - 2016 Long Term Incentive Plan - shares | Apr. 29, 2017 | Dec. 30, 2016 |
Employee Benefit Plans | ||
Number of shares reserved under plan | 1,859,552 | |
Percentage of equity reserved under plan | 5.00% | |
Percentage of total new equity that must be allocated | 3.00% | |
Maximum period in which percentage of total new equity must be allocated | 120 days | |
Percentage of total new equity allocated | 3.00% |
Employee Benefit Plans - Stock
Employee Benefit Plans - Stock options (Details) - Stock Options - 2016 Long Term Incentive Plan | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Employee Benefit Plans | |
Share-based award, expiration period | 10 years |
Share-based award, vesting period | 3 years |
Options | |
Granted (in shares) | shares | 372,597 |
Forfeited (in shares) | shares | (72,448) |
Outstanding at end of period (in shares) | shares | 300,149 |
Options - Weighted Average Exercise Price Per Share | |
Granted (in dollars per share) | $ / shares | $ 28.92 |
Forfeited (in dollars per share) | $ / shares | 28.97 |
Outstanding at end of period (in dollars per share) | $ / shares | $ 28.91 |
Options - Additional information | |
Weighted Average Remaining Contractual Term, Outstanding | 9 years 3 months 18 days |
Employee Benefit Plans - Sto116
Employee Benefit Plans - Stock option valuation assumptions (Details) - Stock Options - 2016 Long Term Incentive Plan $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)shares | |
Black-Scholes option pricing model assumptions: | |
Dividend yield (as a percent) | 0.00% |
Unvested stock options (in shares) | shares | 300,149 |
Unrecognized compensation expense (in dollars) | $ | $ 1.7 |
Unrecognized cost recognition period | 1 year 3 months 18 days |
Employee Benefit Plans - Restri
Employee Benefit Plans - Restricted stock units (Details) - Restricted Stock Units - 2016 Long Term Incentive Plan $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)$ / sharesshares | |
Employee Benefit Plans | |
Share-based award, vesting period | 3 years |
Number of shares for which each unit provides right to receive | 1 |
Restricted Stock Units | |
Granted (in shares) | 775,344 |
Vested (in shares) | (68,814) |
Forfeited (in shares) | (93,730) |
Outstanding at end of period (in shares) | 612,800 |
Average Grant Date Fair Value | |
Granted (in dollars per share) | $ / shares | $ 24.22 |
Exercised (in dollars per share) | $ / shares | 24.21 |
Forfeited (in dollars per share) | $ / shares | 24.48 |
Outstanding at end of period (in dollars per share) | $ / shares | $ 24.19 |
Unrecognized compensation expense | $ | $ 8.5 |
Unrecognized cost recognition period | 1 year 3 months 18 days |
Employee Benefit Plans - Expens
Employee Benefit Plans - Expense (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Employee Benefit Plans | |
Stock-based compensation expense | $ 9,486 |
Stock Options | |
Employee Benefit Plans | |
Stock-based compensation expense | 1,453 |
Restricted Stock Units | |
Employee Benefit Plans | |
Stock-based compensation expense | $ 8,033 |
Employee Benefit Plans - Predec
Employee Benefit Plans - Predecessor Long Term Incentive Plan (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 29, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | |
Employee Benefit Plans | ||||||
Stock-based compensation expense | $ 9,486 | |||||
Assets | $ 1,480,707 | 1,076,982 | $ 1,480,707 | |||
Predecessor | ||||||
Employee Benefit Plans | ||||||
Stock-based compensation expense | (50) | $ (2,583,000) | $ 3,939,000 | |||
Assets | $ 0 | 0 | ||||
Payments with respect to common shares | $ 0 | |||||
Predecessor | Employee Stock Purchase Plan | ||||||
Employee Benefit Plans | ||||||
Purchase price (as a percent) | 15.00% | |||||
Restricted Stock Units | ||||||
Employee Benefit Plans | ||||||
Stock-based compensation expense | $ 8,033 | |||||
Restricted Stock Units | Predecessor | 2006 Long-Term Incentive Plan | ||||||
Employee Benefit Plans | ||||||
Share-based award, vesting period | 3 years | |||||
Time-Based Performance Units | Predecessor | 2006 Long-Term Incentive Plan | ||||||
Employee Benefit Plans | ||||||
Share-based award, vesting period | 3 years | |||||
Total Shareholder Return (TSR) Performance-Based Units | Predecessor | 2006 Long-Term Incentive Plan | ||||||
Employee Benefit Plans | ||||||
Share-based award, vesting period | 3 years |
Employee Benefit Plans - Define
Employee Benefit Plans - Defined Contribution Plans (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Defined Contribution Plans | ||||
Total contributions | $ 1,702 | |||
Predecessor | ||||
Defined Contribution Plans | ||||
Total contributions | $ 638 | $ 2,852 | $ 2,424 | |
Profit Sharing Plan | Predecessor | ||||
Defined Contribution Plans | ||||
Total contributions | (768) | |||
401 (k) Plan | ||||
Defined Contribution Plans | ||||
Total contributions | $ 1,702 | |||
401 (k) Plan | Predecessor | ||||
Defined Contribution Plans | ||||
Total contributions | $ 638 | $ 2,852 | $ 3,192 |
Related Party Transactions - Su
Related Party Transactions - Successor (Details) - USD ($) | Sep. 01, 2017 | Aug. 24, 2017 | Apr. 03, 2017 | Feb. 15, 2017 | Feb. 02, 2017 | Dec. 30, 2016 | Feb. 06, 2018 |
Related Party Transactions | |||||||
Registration rights agreement, Minimum percentage of common stock outstanding | 10.00% | ||||||
Former Chief Executive Officer, John D. Schiller, Jr. | |||||||
Related Party Transactions | |||||||
Amount of severance payment | $ 2,000,000 | ||||||
Severance payment made during the period | $ 2,000,000 | ||||||
Former Chief Executive Officer, John D. Schiller, Jr. | Maximum | |||||||
Related Party Transactions | |||||||
Period of payment for health benefits | 18 months | ||||||
Former Chief Financial Officer, Bruce W. Busmire | |||||||
Related Party Transactions | |||||||
Severance payment made during the period | $ 750,000 | ||||||
Period of severance payments | 18 months | ||||||
Former Chief Operating Officer, Andoni de Pinho | |||||||
Related Party Transactions | |||||||
Severance payment made during the period | $ 750,000 | ||||||
Period of severance payments | 18 months | ||||||
Former Executive VP, CAO and Interim CFO, Hugh A. Menown | |||||||
Related Party Transactions | |||||||
Amount of severance payment | $ 580,000 | ||||||
Period of payment for health benefits | 12 months | ||||||
Severance payment made during the period | $ 580,000 | ||||||
Former Chief Executive Officer, John D. Schiller, Jr. | Consulting Agreement | |||||||
Related Party Transactions | |||||||
Monthly consulting fee | $ 50,000 | ||||||
Former Chief Executive Officer, John D. Schiller, Jr. | Maximum | Consulting Agreement | |||||||
Related Party Transactions | |||||||
Term of agreement | 6 months | ||||||
Former Executive VP, CAO and Interim CFO, Hugh A. Menown | Consulting Agreement | |||||||
Related Party Transactions | |||||||
Monthly consulting fee | $ 28,333.33 | ||||||
Former Executive VP, CAO and Interim CFO, Hugh A. Menown | Maximum | Consulting Agreement | |||||||
Related Party Transactions | |||||||
Term of agreement | 6 months |
Related Party Transactions - Pr
Related Party Transactions - Predecessor - M21K Transactions (Details) - EXXI M21K - Predecessor $ in Millions | Aug. 01, 2015$ / shares | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Aug. 11, 2015 |
Related Party Transactions | ||||
Percentage of investments under the equity method | 20.00% | |||
Equity Method Investee | ||||
Related Party Transactions | ||||
Management fee received (in dollars per BOE) | $ / shares | 0.98 | |||
Revenue from related party | $ 0.2 | $ 3.3 | ||
Equity Method Investee | Guaranteed payment of asset retirement obligation | ||||
Related Party Transactions | ||||
Payment period | 3 years | |||
Payments received related to guarantees | $ 0.3 | $ 3.7 | ||
Equity Method Investee | EP Energy Property | Guaranteed payment of asset retirement obligation | ||||
Related Party Transactions | ||||
Amount of asset retirement obligation of related party for which entity has guaranteed payment | 65 | |||
Amount of other liabilities of related party for which entity has guaranteed payment | 1.8 | |||
Due from related party | 6.3 | |||
Equity Method Investee | LLOG Exploration | Guaranteed payment of asset retirement obligation | ||||
Related Party Transactions | ||||
Amount of asset retirement obligation of related party for which entity has guaranteed payment | 36.7 | |||
Due from related party | 3.3 | |||
Equity Method Investee | Eugene Island 330 and South Marsh Island 128 | Guaranteed payment of asset retirement obligation | ||||
Related Party Transactions | ||||
Amount of asset retirement obligation of related party for which entity has guaranteed payment | 18.6 | |||
Due from related party | $ 1.7 |
Related Party Transactions -123
Related Party Transactions - Predecessor - Consulting Agreements (Details) - Predecessor - USD ($) | Mar. 12, 2016 | Oct. 15, 2015 | Mar. 12, 2015 | Jan. 15, 2015 | Jun. 30, 2016 | Dec. 31, 2015 | Jun. 30, 2015 |
Restricted Stock Units | |||||||
Related Party Transactions | |||||||
Stock repurchased, number of shares | shares | 1,876,219 | ||||||
Stock repurchased, value | $ 1,182,018 | ||||||
Stock repurchased, weighted average price per share | $ 0.63 | ||||||
Director, James LaChance, Interim Chief Strategic Officer | |||||||
Related Party Transactions | |||||||
Minimum capital to be provided by the related party to be eligible for success fee | $ 1,000,000,000 | ||||||
Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon Board's discretion | |||||||
Related Party Transactions | |||||||
Related party transaction, amount of transaction | $ 1,000,000 | ||||||
Director, James LaChance, Interim Chief Strategic Officer | Restricted Stock Units | |||||||
Related Party Transactions | |||||||
Percentage of incentive compensation | 50.00% | ||||||
Restricted stock units awarded (in shares) | 231,482 | ||||||
Restricted stock units, weighted average price per share | $ 2.16 | ||||||
Director, James LaChance, Interim Chief Strategic Officer | Restricted Stock Units | Consulting Agreement, Success fee | |||||||
Related Party Transactions | |||||||
Restricted stock units awarded (in shares) | 1,644,737 | ||||||
Restricted stock units, weighted average price per share | $ 3.04 | ||||||
Director, James LaChance, Interim Chief Strategic Officer | Cash | |||||||
Related Party Transactions | |||||||
Percentage of incentive compensation | 50.00% | ||||||
James LaChance [Member] | Consulting Agreement | |||||||
Related Party Transactions | |||||||
Monthly consulting fee | $ 200,000 | ||||||
Related party expense | $ 100,000 | $ 1,100,000 | |||||
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee | |||||||
Related Party Transactions | |||||||
Incentive compensation to related party | 6,000,000 | ||||||
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon achievement of objective criteria | |||||||
Related Party Transactions | |||||||
Incentive compensation to related party | 5,000,000 | ||||||
Related party transaction, amount of transaction | $ 5,000,000 | ||||||
Maximum | Director, James LaChance, Interim Chief Strategic Officer | Consulting Agreement, Success fee payable upon Board's discretion | |||||||
Related Party Transactions | |||||||
Incentive compensation to related party | $ 1,000,000 |
Related Party Transactions -124
Related Party Transactions - Predecessor - Former CEO (Details) $ in Millions | 6 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2014director | Oct. 09, 2015individual | |
Predecessor | ||||||||
Related Party Transactions | ||||||||
The number of different individuals required for the positions of Chief Executive Officer and Chairman of the Board | individual | 2 | |||||||
Former CEO's personal acquaintances or their affiliates | Services provided | ||||||||
Related Party Transactions | ||||||||
Related party transaction, amount of transaction | $ 10.6 | |||||||
Former CEO's personal acquaintances or their affiliates | Predecessor | Services provided | ||||||||
Related Party Transactions | ||||||||
Related party transaction, amount of transaction | $ 3.3 | $ 35.9 | $ 34.7 | |||||
Managing Director of LP with ownership interest in entity | Predecessor | ||||||||
Related Party Transactions | ||||||||
Number of directors making personal loan to CEO | director | 1 | |||||||
Percentage of company stock owned by related party | 6.30% | |||||||
Entities with which Predecessor Board member has ownership interest | Services provided | ||||||||
Related Party Transactions | ||||||||
Related party transaction, amount of transaction | $ 0 | |||||||
Entities with which Predecessor Board member has ownership interest | Predecessor | Services provided | ||||||||
Related Party Transactions | ||||||||
Related party transaction, amount of transaction | $ 0 | $ 2 | $ 5.6 |
Earnings (Loss) per Share - EPS
Earnings (Loss) per Share - EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 |
Basic and diluted earnings (loss) per share | ||||||||||||||||||
Net income (loss) | $ (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | $ (341,010) | |||||||||
Net (Loss) Income Attributable to Common Stockholders | (406,275) | (341,010) | ||||||||||||||||
Net income (loss) available to common stockholders, Diluted | $ (406,275) | $ (341,010) | ||||||||||||||||
Weighted average shares outstanding for basic EPS | 33,212 | 33,239 | ||||||||||||||||
Weighted average shares outstanding for diluted EPS | 33,212 | 33,239 | ||||||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||
Predecessor | ||||||||||||||||||
Basic and diluted earnings (loss) per share | ||||||||||||||||||
Net income (loss) | $ 2,771,349 | $ (120,738) | $ (195,460) | $ 160,776 | $ (1,310,583) | $ (573,392) | 2,650,611 | $ (1,883,975) | $ (1,918,659) | $ (2,433,838) | ||||||||
Preferred stock dividends | 5,664 | 5,194 | 11,468 | |||||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ 2,771,349 | $ (120,738) | $ (192,612) | $ 158,398 | $ (1,313,393) | $ (576,246) | 2,650,611 | $ (1,889,639) | (1,923,853) | (2,445,306) | ||||||||
Net income (loss) available to common stockholders, Diluted | $ 2,650,611 | $ (1,923,853) | $ (2,445,306) | |||||||||||||||
Weighted average shares outstanding for basic EPS | 98,337 | 94,926 | 95,822 | 94,167 | ||||||||||||||
Add dilutive securities (in shares) | 6,450 | |||||||||||||||||
Weighted average shares outstanding for diluted EPS | 104,787 | 94,926 | 95,822 | 94,167 | ||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ (1.23) | $ (1.97) | $ 1.65 | $ (13.81) | $ (6.08) | $ 26.95 | $ (19.91) | $ (20.08) | $ (25.97) | ||||||||
Diluted (in dollars per share) | $ 26.45 | $ (1.23) | $ (1.97) | $ 1.55 | $ (13.81) | $ (6.08) | $ 25.30 | $ (19.91) | $ (20.08) | $ (25.97) |
Earnings (Loss) per Share - Oth
Earnings (Loss) per Share - Other (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | |
Other disclosures | ||||
Net loss allocated to the participating securities | $ 0 | |||
Anti-dilutive securities (in shares) | 3,132,729 | |||
Predecessor | ||||
Other disclosures | ||||
Anti-dilutive securities (in shares) | 2,119,889 | 9,439,104 | 8,642,434 |
Commitments and Contingencies -
Commitments and Contingencies - Litigation (Details) - Litigation claim to be paid at pro rata share $ in Millions | Jun. 17, 2017USD ($)director | Dec. 31, 2017USD ($) |
Litigation | ||
Amount of claim filed | $ 3.9 | |
Number of directors making personal loan to CEO | director | 1 | |
General unsecured claims, accrual | $ 1.5 | $ 1.5 |
Commitments and Contingencie128
Commitments and Contingencies - Future Minimum Lease Commitments (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments and Contingencies | |
Year ending December 31, 2018 | $ 36,035 |
Year ending December 31, 2019 | 36,509 |
Year ending December 31, 2020 | 43,545 |
Year ending December 31, 2021 | 49,598 |
Year ending December 31, 2022 | 48,575 |
Thereafter | 152,176 |
Total | $ 366,438 |
Commitments and Contingencie129
Commitments and Contingencies - Additional Lease Information (Details) $ in Millions | Jun. 30, 2015USD ($)item | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($)item |
Leases, Excluding GIGS Lease | |||||
Lease Commitments | |||||
Rent expense | $ 24.1 | ||||
Predecessor | Leases, Excluding GIGS Lease | |||||
Lease Commitments | |||||
Rent expense | $ 11.9 | $ 6 | $ 6.4 | ||
Predecessor | GiGS Lease | |||||
Lease Commitments | |||||
Rent expense | $ 17 | ||||
Primary term of the lease | 11 years | ||||
Number of renewal options under the terms of the operating lease | item | 1 | 1 | |||
Average annual lease payment over life of lease | $ 40.5 | $ 40.5 | |||
Right of first refusal period after lease term | 2 years | ||||
Predecessor | GiGS Lease | Maximum | |||||
Lease Commitments | |||||
Lease renewal term | 9 years | ||||
Percentage of expected useful life of the property for renewal option | 75.00% |
Commitments and Contingencie130
Commitments and Contingencies - Letters of Credit and Performance Bonds (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Mar. 13, 2017 | Dec. 30, 2016 |
Letters of Credit and Performance Bonds | |||
Performance bonds outstanding | $ 334.1 | ||
Cash collateral | 49.8 | ||
Exit Facility | |||
Letters of Credit and Performance Bonds | |||
Letters of credit | 202.6 | ||
Exit Revolving Facility | |||
Letters of Credit and Performance Bonds | |||
Letters of credit | 200 | $ 200 | $ 225 |
Performance Bond, Lease and area bonds | |||
Letters of Credit and Performance Bonds | |||
Performance bonds outstanding | 182.4 | ||
Performance Bonds, Wells and facilities | |||
Letters of Credit and Performance Bonds | |||
Performance bonds outstanding | $ 151.7 |
Commitments and Contingencie131
Commitments and Contingencies - Drilling Rig Commitments (Details) - Drilling Rig Contracts $ in Millions | 2 Months Ended | 12 Months Ended |
Mar. 15, 2018 | Dec. 31, 2017USD ($)contract | |
Drilling Rig Commitments | ||
Drilling rig commitments | $ 0.6 | |
Committed contracts with contract terms between 2 and 6 months | $ 14 | |
Number of contracts | contract | 2 | |
Minimum | ||
Drilling Rig Commitments | ||
Term of contract | 2 months | |
Maximum | ||
Drilling Rig Commitments | ||
Term of contract | 6 months |
Commitments and Contingencie132
Commitments and Contingencies - Other (Details) $ in Millions | Dec. 31, 2017USD ($) |
Bonding requirements | |
Other | |
Restricted cash | $ 25.7 |
Future plugging, abandonment and other decommissioning costs | |
Other | |
Restricted cash | $ 6.1 |
Income Taxes - Successor Income
Income Taxes - Successor Income Taxes - Emergence (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 31, 2016 | Sep. 30, 2012 |
Income Taxes | |||||||
Valuation allowance | $ 306,206 | $ 167,645 | |||||
Tax basis of asset retirement obligation | 0 | ||||||
Increase in valuation allowance | 224,000 | ||||||
Predecessor | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | ||||||
Face value of notes | $ 5,500 | ||||||
Percentage of stock cancelled | 100.00% | ||||||
Withholding tax rate (as a percent) | 30.00% | 30.00% | |||||
Valuation allowance | $ 1,029,300 | $ 1,029,300 | $ 379,300 | ||||
Additional tax basis | $ 633,000 | ||||||
Increase in amount related to the change in total CODI excluded | 663,000 | ||||||
Change in estimates of tax attributes | $ 30,000 | ||||||
Increase in valuation allowance | $ 224,000 | $ 650,000 | $ 356,800 | ||||
4.14% Promissory Note due 2017 | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | 4.14% | ||||
4.14% Promissory Note due 2017 | Predecessor | |||||||
Income Taxes | |||||||
Debt instrument, stated interest rate (as a percent) | 4.14% | 4.14% | |||||
Face value of notes | $ 5,500 | $ 5,500 |
Income Taxes - Successor Inc134
Income Taxes - Successor Income Taxes - CODI (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Cancellation of Debt Income | |
Pre-tax reductions in net operating loss carryovers | $ 681 |
Pre-tax reductions in oil and natural gas properties | 915 |
Pre-tax reductions in EPL stock basis | 304 |
Pre-tax reductions in others | 18 |
CODI excluded requiring attribute reduction | 1,918 |
As reported | |
Cancellation of Debt Income | |
Pre-tax reductions in net operating loss carryovers | 486 |
Pre-tax reductions in oil and natural gas properties | 1,485 |
Pre-tax reductions in EPL stock basis | 543 |
Pre-tax reductions in others | 67 |
CODI excluded requiring attribute reduction | $ 2,581 |
Income Taxes - Successor Inc135
Income Taxes - Successor Income Taxes - Additional information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Valuation Allowance | |||
Cash paid for income taxes | $ 0 | ||
Net operating loss carryovers | $ 339 | $ 339 | |
Fresh Start | |||
Valuation Allowance | |||
Effective income tax rate (benefit) (as a percent) | 0.00% | ||
Increase in stock ownership threshold (as a percent) | 50.00% | ||
Look-back period | 3 years |
Income Taxes - Predecessor Inco
Income Taxes - Predecessor Income taxes (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Jun. 30, 2016 | Dec. 30, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 31, 2016 |
Income Taxes | |||||||
Withholding taxes paid | $ 0 | ||||||
Increase (decrease) in valuation allowance | $ 224,000 | ||||||
Valuation allowance | 306,206 | $ 167,645 | |||||
Predecessor | |||||||
Income Taxes | |||||||
Withholding tax rate (as a percent) | 30.00% | 30.00% | |||||
Increase (decrease) in valuation allowance | $ 224,000 | $ 650,000 | $ 356,800 | ||||
Valuation allowance | $ 1,029,300 | $ 1,029,300 | $ 379,300 |
Income Taxes - Income before in
Income Taxes - Income before income tax (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 |
Income Taxes | |||||||||||
U.S. (loss) income | $ (406,275) | $ (341,010) | |||||||||
(Loss) Income Before Income Taxes | $ (406,275) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (125,941) | $ (341,010) | ||||
Predecessor | |||||||||||
Income Taxes | |||||||||||
U.S. (loss) income | $ 2,650,611 | $ (1,913,626) | $ (3,050,659) | ||||||||
Non-U.S. (loss) income | (5,120) | 3,471 | |||||||||
(Loss) Income Before Income Taxes | $ 2,650,611 | $ (1,883,924) | $ (1,918,746) | $ (3,047,188) |
Income Taxes - Components of in
Income Taxes - Components of income tax provision (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Deferred | ||||
Income tax benefit | $ 0 | |||
Predecessor | ||||
Current | ||||
U.S. | $ 933 | |||
State | $ (87) | 99 | ||
Total current | (87) | 1,032 | ||
Deferred | ||||
U.S. | (564,569) | |||
State | (49,813) | |||
Total deferred | (614,382) | |||
Income tax benefit | $ 51 | $ (87) | $ (613,350) |
Income Taxes - Reconciliation (
Income Taxes - Reconciliation (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 |
Income Taxes | ||||||||||||
(Loss) income before income taxes | $ (406,275) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (125,941) | $ (341,010) | |||||
Statutory rate (as a percent) | 35.00% | 35.00% | ||||||||||
Income tax (benefit) expense computed at statutory rate | $ (142,196) | $ (119,354) | ||||||||||
Reconciling items | ||||||||||||
Change in valuation allowance | $ 142,196 | 138,561 | ||||||||||
Non-deductible transaction and restructuring costs | 894 | |||||||||||
Return to provision adjustments | (224,339) | |||||||||||
Tax Cuts and Jobs Act of 2017 | 204,137 | |||||||||||
Fresh start adjustments to deferred tax balances: | ||||||||||||
Other - Net | 101 | |||||||||||
Income tax benefit | $ 0 | |||||||||||
Predecessor | ||||||||||||
Income Taxes | ||||||||||||
(Loss) income before income taxes | $ 2,650,611 | $ (1,883,924) | $ (1,918,746) | $ (3,047,188) | ||||||||
Statutory rate (as a percent) | 35.00% | 35.00% | 35.00% | |||||||||
Income tax (benefit) expense computed at statutory rate | $ 927,714 | $ (671,561) | $ (1,066,516) | |||||||||
Reconciling items | ||||||||||||
Federal withholding obligation | 8,161 | 10,331 | ||||||||||
Nontaxable foreign income | 1,791 | 91 | ||||||||||
Change in valuation allowance | (1,029,335) | 650,011 | 356,798 | |||||||||
State income taxes (benefit), net of federal tax benefit | (87) | (32,314) | ||||||||||
Non-deductible transaction and restructuring costs | 36,874 | 440 | ||||||||||
Tax basis in shortfall on partnership dissolution | 6,501 | |||||||||||
Fresh start adjustments to deferred tax balances: | ||||||||||||
Asset retirement obligation | 190,715 | |||||||||||
Net operating loss | 163,027 | |||||||||||
Accrued interest expense | 115,560 | |||||||||||
Oil and natural gas properties and other property and equipment | 611,834 | |||||||||||
Deferred state income taxes | 54,793 | |||||||||||
Withholding taxes | (81,635) | |||||||||||
Cancellation of stockholders deficit | (290,665) | |||||||||||
Cancellation of indebtedness income | (702,972) | |||||||||||
Other fresh start deferred income taxes, net | 3,284 | |||||||||||
Goodwill impairment | 115,253 | |||||||||||
Other - Net | $ 806 | 5,097 | 2,567 | |||||||||
Income tax benefit | $ 51 | $ (87) | $ (613,350) | |||||||||
Forecast | ||||||||||||
Income Taxes | ||||||||||||
Statutory rate (as a percent) | 21.00% |
Income Taxes - Components of de
Income Taxes - Components of deferred taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | Dec. 29, 2016 |
Deferred tax assets - non current | |||||||
Oil, natural gas properties and other property and equipment | $ 66,297 | ||||||
Asset retirement obligation | $ 257,988 | $ 257,988 | 139,619 | ||||
Tax loss carryforwards on U.S. operations | 71,268 | ||||||
Employee benefit plans | 1,698 | ||||||
Tax partnership activity | 676 | ||||||
Derivative instruments and other | 6,839 | ||||||
Other | 11,120 | 11,120 | 19,809 | ||||
Total deferred tax assets | 269,108 | 269,108 | 306,206 | ||||
Deferred tax liabilities | |||||||
Oil, natural gas properties and other property and equipment | (101,463) | (101,463) | |||||
Total deferred tax liabilities | (101,463) | (101,463) | |||||
Valuation allowance | (167,645) | (167,645) | (306,206) | ||||
Net operating loss carryovers | $ 339,000 | $ 339,000 | $ 339,000 | ||||
Statutory rate (as a percent) | 35.00% | 35.00% | |||||
Forecast | |||||||
Deferred tax liabilities | |||||||
Statutory rate (as a percent) | 21.00% | ||||||
Predecessor | |||||||
Deferred tax liabilities | |||||||
Valuation allowance | $ (1,029,300) | $ (379,300) | |||||
Statutory rate (as a percent) | 35.00% | 35.00% | 35.00% | ||||
U.S. | Predecessor | |||||||
Deferred tax liabilities | |||||||
Net operating loss carryovers | $ 681,000 |
Concentrations of Credit Risk (
Concentrations of Credit Risk (Details) - instrument | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Predecessor | ||||
Derivative, Number of Instruments Held | ||||
Derivative instruments outstanding | 0 | 0 | ||
Chevron | Revenue [Member] | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 26.00% | |||
Chevron | Revenue [Member] | Predecessor | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 26.00% | 22.00% | 24.00% | |
Shell | Revenue [Member] | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 25.00% | |||
Shell | Revenue [Member] | Predecessor | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 26.00% | 21.00% | 29.00% | |
Plains | Revenue [Member] | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 18.00% | |||
Trafigura | Revenue [Member] | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 12.00% | |||
Trafigura | Revenue [Member] | Predecessor | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 27.00% | 22.00% | ||
ExxonMobil | Revenue [Member] | Predecessor | ||||
Concentration Risk [Line Items] | ||||
Percentage of total oil and natural gas revenues | 26.00% |
Fair Value - General (Details)
Fair Value - General (Details) $ in Millions | Dec. 31, 2017USD ($) |
Fair Value | |
Fair value adjustment related to property and equipment | $ 1,007.4 |
Fair value adjustment related to asset retirement obligation | 185.6 |
Fair value adjustment related to common stock warrants | $ 8.1 |
Fair Value - Financial instrume
Fair Value - Financial instruments (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | |
Liabilities: | |||
Oil and Natural Gas Derivatives, Liabilities | $ 32,567 | ||
Level 2 | |||
Liabilities: | |||
Oil and Natural Gas Derivatives, Liabilities | 32,567 | ||
Level 3 | |||
Fair value of financial instruments | |||
Transfers into Level 3 | 0 | ||
Transfers out of Level 3 | $ 0 | ||
Predecessor | Level 3 | |||
Fair value of financial instruments | |||
Transfers into Level 3 | $ 0 | $ 0 | |
Transfers out of Level 3 | $ 0 | $ 0 |
Fair Value - Long-term debt ins
Fair Value - Long-term debt instruments (Details) - Level 2 - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Carrying Value | ||
Long-Term Debt | ||
Long-term debt instruments | $ 73,996 | $ 73,996 |
Estimated of Fair Value | ||
Long-Term Debt | ||
Long-term debt instruments | 73,996 | 73,996 |
Exit Facility | Carrying Value | ||
Long-Term Debt | ||
Long-term debt instruments | 73,996 | 73,996 |
Exit Facility | Estimated of Fair Value | ||
Long-Term Debt | ||
Long-term debt instruments | $ 73,996 | $ 73,996 |
Fair Value - Changes to Level 3
Fair Value - Changes to Level 3 financial instruments (Details) - Predecessor - USD ($) $ in Thousands | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Level 3 financial instruments | ||
Balance at beginning of period | $ 33 | $ 6,910 |
Vested | (775) | |
Grants charged to general and administrative expense | 760 | (6,877) |
Balance at end of period | $ 18 | $ 33 |
Prepayments and Accrued Liab146
Prepayments and Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Prepaid expenses and other current assets | ||
Advances to joint interest partners | $ 1,381 | $ 650 |
Insurance | 5,949 | 9,600 |
Inventory | 394 | 470 |
Royalty deposit | 1,021 | 1,273 |
Other | 12,857 | 5,987 |
Total prepaid expenses and other current assets | 21,602 | 17,980 |
Accrued liabilities | ||
Advances from joint interest partners | 81 | 374 |
Employee benefits and payroll | 6,791 | 4,491 |
Interest payable | 185 | 233 |
Accrued hedge payable | 2,491 | |
Undistributed oil and gas proceeds | 20,079 | 22,715 |
Severance taxes payable | 558 | 628 |
Escrowed reorganization expenses | 25,987 | |
Other | 15,309 | 1,247 |
Total accrued liabilities | $ 45,494 | $ 55,675 |
Comparative Period Informati147
Comparative Period Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Total Revenues | $ 93,838 | $ 115,701 | $ 144,019 | $ 158,086 | |||||||||||||||
Operating loss | $ (406,275) | (211,462) | (31,556) | (22,675) | (60,735) | $ (83,410) | $ (114,966) | $ (326,428) | |||||||||||
(Loss) income before income taxes | (406,275) | (35,157) | (26,237) | (64,547) | (90,784) | (125,941) | (341,010) | ||||||||||||
Income tax benefit | 0 | ||||||||||||||||||
Net (Loss) Income | (406,275) | (215,069) | (35,157) | (26,237) | (64,547) | (90,784) | $ (406,275) | (125,941) | (341,010) | ||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ (406,275) | $ (341,010) | |||||||||||||||||
Earnings (Loss) per Share | |||||||||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||||||||
Basic (in shares) | 33,212 | 33,239 | |||||||||||||||||
Diluted (in shares) | 33,212 | 33,239 | |||||||||||||||||
Net cash used in operating activities | $ 45,638 | ||||||||||||||||||
Net cash provided by (used in) investing activities | (55,063) | ||||||||||||||||||
Net cash used in financing activities | (4,214) | ||||||||||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (13,639) | ||||||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | 40,774 | 40,774 | 40,774 | $ 185,860 | $ 406,300 | ||||||||||||
Predecessor | |||||||||||||||||||
Total Revenues | $ 153,723 | $ 142,963 | $ 148,395 | $ 116,285 | $ 184,615 | $ 257,823 | 296,686 | $ 442,438 | |||||||||||
Operating loss | 12,795 | (83,329) | (168,119) | (417,866) | (1,513,148) | (918,200) | (70,534) | (2,431,348) | $ (3,017,333) | $ (2,710,891) | |||||||||
(Loss) income before income taxes | 2,650,611 | (1,883,924) | (1,918,746) | (3,047,188) | |||||||||||||||
Income tax benefit | 51 | (87) | (613,350) | ||||||||||||||||
Net (Loss) Income | 2,771,349 | (120,738) | (195,460) | 160,776 | (1,310,583) | (573,392) | 2,650,611 | (1,883,975) | (1,918,659) | (2,433,838) | |||||||||
Preferred stock dividends | 5,664 | 5,194 | 11,468 | ||||||||||||||||
Net (Loss) Income Attributable to Common Stockholders | $ 2,771,349 | $ (120,738) | $ (192,612) | $ 158,398 | $ (1,313,393) | $ (576,246) | $ 2,650,611 | $ (1,889,639) | $ (1,923,853) | $ (2,445,306) | |||||||||
Earnings (Loss) per Share | |||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ (1.23) | $ (1.97) | $ 1.65 | $ (13.81) | $ (6.08) | $ 26.95 | $ (19.91) | $ (20.08) | $ (25.97) | |||||||||
Diluted (in dollars per share) | $ 26.45 | $ (1.23) | $ (1.97) | $ 1.55 | $ (13.81) | $ (6.08) | $ 25.30 | $ (19.91) | $ (20.08) | $ (25.97) | |||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||||||||
Basic (in shares) | 98,337 | 94,926 | 95,822 | 94,167 | |||||||||||||||
Diluted (in shares) | 104,787 | 94,926 | 95,822 | 94,167 | |||||||||||||||
Net cash used in operating activities | $ (17,473) | $ (89,924) | $ (166,655) | $ 330,753 | |||||||||||||||
Net cash provided by (used in) investing activities | 11,706 | (82,872) | (122,913) | (460,448) | |||||||||||||||
Net cash used in financing activities | (32,123) | (258,162) | (264,022) | 740,737 | |||||||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (37,890) | (430,958) | (553,590) | 611,042 | |||||||||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | 77,781 | 2,330,500 | 2,814,028 | $ 2,421,884 | ||||||||||
Gain on settlement of liabilities subject to compromise | $ (1,983,920) | $ (1,983,900) | (1,983,920) | ||||||||||||||||
Fair value adjustment | 840,300 | 840,256 | |||||||||||||||||
Reorganization expenses | 58,000 | 32,600 | 90,568 | 14,201 | |||||||||||||||
Gain on early extinguishment of debt | $ 777,000 | $ 290,300 | $ 458,300 | $ 748,600 | 1,525,596 | ||||||||||||||
As reported | |||||||||||||||||||
Operating loss | (27,979) | (20,081) | (61,503) | (81,584) | (109,563) | ||||||||||||||
(Loss) income before income taxes | (31,580) | (23,643) | (65,315) | (88,958) | (120,538) | ||||||||||||||
Net (Loss) Income | (31,580) | (23,643) | (65,315) | (88,958) | (120,538) | ||||||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||||||||
Impairment of oil and natural gas properties | $ (2,357) | $ (848) | $ 44,054 | $ 43,206 | $ 40,849 | ||||||||||||||
Predecessor | |||||||||||||||||||
Operating loss | 12,795 | (83,329) | (70,534) | (3,017,333) | |||||||||||||||
(Loss) income before income taxes | (120,738) | 2,650,611 | (1,918,746) | ||||||||||||||||
Income tax benefit | (87) | ||||||||||||||||||
Net (Loss) Income | $ 2,771,349 | (120,738) | $ 2,650,611 | (1,918,659) | |||||||||||||||
Preferred stock dividends | 5,194 | ||||||||||||||||||
Net (Loss) Income Attributable to Common Stockholders | (1,923,853) | ||||||||||||||||||
Earnings (Loss) per Share | |||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ 26.95 | |||||||||||||||||
Diluted (in dollars per share) | $ 26.45 | $ 25.30 | |||||||||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||||||||
Basic (in shares) | 98,850 | 98,337 | |||||||||||||||||
Diluted (in shares) | 104,787 | 104,787 | |||||||||||||||||
Net cash used in operating activities | $ (17,473) | (166,655) | |||||||||||||||||
Net cash provided by (used in) investing activities | 11,706 | (122,913) | |||||||||||||||||
Net cash used in financing activities | (32,123) | (264,022) | |||||||||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (37,890) | (553,590) | |||||||||||||||||
Impairment of oil and natural gas properties | 77,558 | 77,781 | 2,814,028 | ||||||||||||||||
Gain on early extinguishment of debt | 1,525,596 | ||||||||||||||||||
Predecessor | As reported | |||||||||||||||||||
Operating loss | $ 11,708 | (93,737) | (82,029) | (3,017,425) | |||||||||||||||
(Loss) income before income taxes | (131,146) | 2,653,903 | (1,918,838) | ||||||||||||||||
Income tax benefit | (87) | ||||||||||||||||||
Net (Loss) Income | $ 2,785,049 | (131,146) | $ 2,653,903 | (1,918,751) | |||||||||||||||
Preferred stock dividends | 8,394 | ||||||||||||||||||
Net (Loss) Income Attributable to Common Stockholders | (1,927,145) | ||||||||||||||||||
Earnings (Loss) per Share | |||||||||||||||||||
Basic (in dollars per share) | $ 28.17 | $ 26.99 | |||||||||||||||||
Diluted (in dollars per share) | $ 26.58 | $ 25.33 | |||||||||||||||||
Weighted Average Number of Common Shares Outstanding | |||||||||||||||||||
Basic (in shares) | 98,850 | 98,337 | |||||||||||||||||
Diluted (in shares) | 104,787 | 104,787 | |||||||||||||||||
Net cash used in operating activities | $ (17,473) | (166,655) | |||||||||||||||||
Net cash provided by (used in) investing activities | 11,706 | (122,913) | |||||||||||||||||
Net cash used in financing activities | (32,123) | (264,022) | |||||||||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (37,890) | (553,590) | |||||||||||||||||
Impairment of oil and natural gas properties | $ 86,820 | $ 86,820 | 2,813,570 | ||||||||||||||||
Gain on early extinguishment of debt | $ 1,525,596 |
Selected Quarterly Financial148
Selected Quarterly Financial Data – Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Revenues | $ 93,838 | $ 115,701 | $ 144,019 | $ 158,086 | |||||||||||||||
Operating loss | $ (406,275) | (211,462) | (31,556) | (22,675) | (60,735) | $ (83,410) | $ (114,966) | $ (326,428) | |||||||||||
Net (Loss) Income | (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | (341,010) | ||||||||||
Net income (loss) attributable to common stockholders | $ (406,275) | $ (341,010) | |||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | |||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (6.47) | $ (1.06) | $ (0.79) | $ (1.94) | $ (2.73) | $ (3.79) | |||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | |||||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | $ 40,774 | $ 40,774 | $ 40,774 | $ 185,860 | $ 406,300 | ||||||||||||
Predecessor | |||||||||||||||||||
Revenues | $ 153,723 | $ 142,963 | $ 148,395 | $ 116,285 | $ 184,615 | $ 257,823 | 296,686 | $ 442,438 | |||||||||||
Operating loss | 12,795 | (83,329) | (168,119) | (417,866) | (1,513,148) | (918,200) | (70,534) | (2,431,348) | $ (3,017,333) | $ (2,710,891) | |||||||||
Net (Loss) Income | 2,771,349 | (120,738) | (195,460) | 160,776 | (1,310,583) | (573,392) | 2,650,611 | (1,883,975) | (1,918,659) | (2,433,838) | |||||||||
Preferred stock dividends | (2,848) | 2,378 | 2,810 | 2,854 | |||||||||||||||
Net income (loss) attributable to common stockholders | $ 2,771,349 | $ (120,738) | $ (192,612) | $ 158,398 | $ (1,313,393) | $ (576,246) | $ 2,650,611 | $ (1,889,639) | $ (1,923,853) | $ (2,445,306) | |||||||||
Net income (loss) per share attributable to common stockholders(1) | |||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ (1.23) | $ (1.97) | $ 1.65 | $ (13.81) | $ (6.08) | $ 26.95 | $ (19.91) | $ (20.08) | $ (25.97) | |||||||||
Diluted (in dollars per share) | $ 26.45 | $ (1.23) | $ (1.97) | $ 1.55 | $ (13.81) | $ (6.08) | $ 25.30 | $ (19.91) | $ (20.08) | $ (25.97) | |||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | $ 77,781 | $ 2,330,500 | $ 2,814,028 | $ 2,421,884 | ||||||||||
Reorganization items | 2,733,608 | (14,201) | |||||||||||||||||
Gain on early extinguishment of debt | $ 777,000 | $ 290,300 | $ 458,300 | $ 748,600 | 1,525,596 | ||||||||||||||
Gain on settlement of liabilities subject to compromise | $ 1,983,920 | $ 1,983,900 | 1,983,920 | ||||||||||||||||
Fair value adjustment | 840,300 | 840,256 | |||||||||||||||||
Reorganization expenses | 58,000 | 32,600 | 90,568 | 14,201 | |||||||||||||||
Adjustment | |||||||||||||||||||
Operating loss | $ (3,577) | $ (2,594) | 768 | (1,826) | (5,403) | ||||||||||||||
Net (Loss) Income | $ (3,577) | $ (2,594) | $ 768 | $ (1,826) | $ (5,403) | ||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | |||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (0.11) | $ (0.08) | $ 0.02 | $ (0.05) | $ (0.16) | ||||||||||||||
Impairment of oil and natural gas properties | $ 2,357 | $ 848 | $ (3,280) | $ (2,432) | $ (75) | ||||||||||||||
Predecessor | |||||||||||||||||||
Operating loss | 12,795 | (83,329) | (70,534) | (3,017,333) | |||||||||||||||
Net (Loss) Income | $ 2,771,349 | $ (120,738) | $ 2,650,611 | (1,918,659) | |||||||||||||||
Net income (loss) attributable to common stockholders | $ (1,923,853) | ||||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | |||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (1.23) | $ (20.08) | |||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ 26.95 | |||||||||||||||||
Diluted (in dollars per share) | $ 26.45 | $ 25.30 | |||||||||||||||||
Impairment of oil and natural gas properties | $ 77,558 | $ 77,781 | $ 2,814,028 | ||||||||||||||||
Reorganization items | (32,633) | 2,733,608 | (14,201) | ||||||||||||||||
Gain on early extinguishment of debt | 1,525,596 | ||||||||||||||||||
Predecessor | Adjustment | |||||||||||||||||||
Operating loss | $ 1,087 | 10,408 | 11,495 | 92 | |||||||||||||||
Net (Loss) Income | $ (13,700) | $ 10,408 | $ (3,292) | 92 | |||||||||||||||
Net income (loss) attributable to common stockholders | $ 3,292 | ||||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | |||||||||||||||||||
Basic and Diluted (in dollars per share) | $ 0.11 | $ 0.03 | |||||||||||||||||
Basic (in dollars per share) | $ (0.14) | $ (0.04) | |||||||||||||||||
Diluted (in dollars per share) | $ (0.13) | $ (0.03) | |||||||||||||||||
Impairment of oil and natural gas properties | $ (9,262) | $ (9,039) | $ 458 | ||||||||||||||||
Reorganization items | $ (14,787) |
Selected Quarterly Financial149
Selected Quarterly Financial Data - Unaudited adjustments (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2014 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 |
Revenues | ||||||||||||||||||||
Oil sales | $ 113,697 | $ 118,484 | $ 133,793 | $ 252,277 | $ 365,974 | $ 481,922 | ||||||||||||||
Natural gas liquids sales | 2,209 | 2,370 | 2,227 | 4,597 | 6,806 | 8,542 | ||||||||||||||
Natural gas sales | 12,261 | 13,753 | 18,368 | 32,121 | 44,382 | 53,805 | ||||||||||||||
(Loss) Gain on derivative financial instruments | (12,466) | 9,412 | 3,698 | 13,110 | 644 | (32,625) | ||||||||||||||
Total Revenues | 115,701 | 144,019 | 158,086 | 302,105 | 417,806 | 511,644 | ||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 77,822 | 83,655 | 77,267 | 160,922 | 238,744 | 319,671 | ||||||||||||||
Production taxes | 471 | 482 | 239 | 721 | 1,192 | 1,355 | ||||||||||||||
Gathering and transportation | (2,441) | 2,678 | 11,222 | 13,900 | 11,459 | 21,666 | ||||||||||||||
Pipeline facility fee | 10,495 | 10,494 | 10,494 | 20,988 | 31,483 | 41,977 | ||||||||||||||
Depreciation, depletion and amortization | 36,131 | 38,685 | 41,896 | 80,581 | 116,712 | 150,151 | ||||||||||||||
Accretion of asset retirement obligations | 9,753 | 9,984 | 13,081 | 23,065 | 32,818 | 42,780 | ||||||||||||||
Impairment of oil and natural gas properties | $ 406,275 | $ 145,100 | 40,774 | 40,774 | 40,774 | 185,860 | $ 406,300 | |||||||||||||
General and administrative expense | 15,026 | 20,716 | 23,848 | 42,320 | 57,346 | 72,057 | ||||||||||||||
Reorganization items | 2,244 | 2,244 | 2,555 | |||||||||||||||||
Total Costs and Expenses | 406,275 | 147,257 | 166,694 | 218,821 | 385,515 | 532,772 | 838,072 | |||||||||||||
Operating Loss | (406,275) | (211,462) | (31,556) | (22,675) | (60,735) | (83,410) | (114,966) | (326,428) | ||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 52 | 80 | 22 | 102 | 154 | 254 | ||||||||||||||
Interest expense | (3,653) | (3,642) | (3,834) | (7,476) | (11,129) | (14,836) | ||||||||||||||
Total Other (Expense) Income, net | (3,601) | (3,562) | (3,812) | (7,374) | (10,975) | (14,582) | ||||||||||||||
Loss Before Reorganization Items and Income Taxes | (406,275) | (341,010) | ||||||||||||||||||
(Loss) Income Before Income Taxes | (406,275) | (35,157) | (26,237) | (64,547) | (90,784) | (125,941) | (341,010) | |||||||||||||
Income Tax Benefit | 0 | |||||||||||||||||||
Net (Loss) Income | $ (406,275) | $ (215,069) | $ (35,157) | $ (26,237) | $ (64,547) | $ (90,784) | $ (406,275) | $ (125,941) | $ (341,010) | |||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (6.47) | $ (1.06) | $ (0.79) | $ (1.94) | $ (2.73) | $ (3.79) | ||||||||||||||
Basic (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||||
Diluted (in dollars per share) | $ (12.23) | $ (10.26) | ||||||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 33,212 | 33,239 | ||||||||||||||||||
Diluted (in shares) | 33,212 | 33,239 | ||||||||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | |||||||||||||||
Predecessor | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | 256,050 | $ 532,505 | $ 1,025,017 | |||||||||||||||||
Natural gas liquids sales | 3,533 | 14,852 | 27,714 | |||||||||||||||||
Natural gas sales | 37,103 | 69,255 | 117,282 | |||||||||||||||||
(Loss) Gain on derivative financial instruments | 90,506 | 235,439 | ||||||||||||||||||
Total Revenues | 296,686 | 707,118 | 1,405,452 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 136,578 | 328,183 | 449,972 | |||||||||||||||||
Production taxes | 482 | 1,442 | 8,385 | |||||||||||||||||
Gathering and transportation | 5,910 | 33,156 | 34,707 | |||||||||||||||||
Pipeline facility fee | 20,330 | 40,659 | ||||||||||||||||||
Depreciation, depletion and amortization | 60,202 | 339,539 | 705,521 | |||||||||||||||||
Accretion of asset retirement obligations | 38,380 | 64,708 | 50,081 | |||||||||||||||||
Impairment of oil and natural gas properties | $ 77,600 | $ 143,100 | $ 340,500 | $ 1,425,800 | $ 904,700 | 77,781 | $ 2,330,500 | 2,814,028 | 2,421,884 | |||||||||||
Goodwill impairment | $ 329,300 | 329,293 | ||||||||||||||||||
General and administrative expense | 27,557 | 102,736 | 116,500 | |||||||||||||||||
Total Costs and Expenses | 367,220 | 3,724,451 | 4,116,343 | |||||||||||||||||
Operating Loss | $ 12,795 | (83,329) | (168,119) | (417,866) | (1,513,148) | (918,200) | (70,534) | (2,431,348) | (3,017,333) | (2,710,891) | ||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 117 | 3,596 | 4,176 | |||||||||||||||||
Interest expense | (12,580) | (405,658) | (323,308) | |||||||||||||||||
Total Other (Expense) Income, net | (12,463) | 1,112,788 | (336,297) | |||||||||||||||||
Loss Before Reorganization Items and Income Taxes | (82,997) | (1,904,545) | (3,047,188) | |||||||||||||||||
Reorganization items | 2,733,608 | (14,201) | ||||||||||||||||||
(Loss) Income Before Income Taxes | 2,650,611 | (1,883,924) | (1,918,746) | (3,047,188) | ||||||||||||||||
Income Tax Benefit | 51 | (87) | (613,350) | |||||||||||||||||
Net (Loss) Income | $ 2,771,349 | $ (120,738) | $ (195,460) | $ 160,776 | $ (1,310,583) | $ (573,392) | $ 2,650,611 | $ (1,883,975) | $ (1,918,659) | $ (2,433,838) | ||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ (1.23) | $ (1.97) | $ 1.65 | $ (13.81) | $ (6.08) | $ 26.95 | $ (19.91) | $ (20.08) | $ (25.97) | ||||||||||
Diluted (in dollars per share) | $ 26.45 | $ (1.23) | $ (1.97) | $ 1.55 | $ (13.81) | $ (6.08) | $ 25.30 | $ (19.91) | $ (20.08) | $ (25.97) | ||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 98,337 | 94,926 | 95,822 | 94,167 | ||||||||||||||||
Diluted (in shares) | 104,787 | 94,926 | 95,822 | 94,167 | ||||||||||||||||
As reported | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ 114,991 | $ 118,180 | $ 133,621 | $ 251,801 | $ 366,792 | |||||||||||||||
Natural gas liquids sales | 2,209 | 2,370 | 2,227 | 4,597 | 6,806 | |||||||||||||||
Natural gas sales | 12,261 | 13,753 | 18,368 | 32,121 | 44,382 | |||||||||||||||
(Loss) Gain on derivative financial instruments | (12,466) | 9,412 | 3,698 | 13,110 | 644 | |||||||||||||||
Total Revenues | 116,995 | 143,715 | 157,914 | 301,629 | 418,624 | |||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 77,822 | 85,336 | 75,157 | 160,493 | 238,315 | |||||||||||||||
Production taxes | 471 | 482 | 239 | 721 | 1,192 | |||||||||||||||
Gathering and transportation | (2,441) | 2,678 | 11,222 | 13,900 | 11,459 | |||||||||||||||
Pipeline facility fee | 10,495 | 10,494 | 10,494 | 20,988 | 31,483 | |||||||||||||||
Depreciation, depletion and amortization | 36,066 | 38,661 | 42,006 | 80,667 | 116,733 | |||||||||||||||
Accretion of asset retirement obligations | 9,892 | 10,050 | 12,397 | 22,447 | 32,339 | |||||||||||||||
Impairment of oil and natural gas properties | (2,357) | (848) | 44,054 | 43,206 | 40,849 | |||||||||||||||
General and administrative expense | 15,026 | 20,716 | 23,848 | 42,320 | 57,346 | |||||||||||||||
Reorganization items | (3,773) | (1,529) | (1,529) | |||||||||||||||||
Total Costs and Expenses | 144,974 | 163,796 | 219,417 | 383,213 | 528,187 | |||||||||||||||
Operating Loss | (27,979) | (20,081) | (61,503) | (81,584) | (109,563) | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 52 | 80 | 22 | 102 | 154 | |||||||||||||||
Interest expense | (3,653) | (3,642) | (3,834) | (7,476) | (11,129) | |||||||||||||||
Total Other (Expense) Income, net | (3,601) | (3,562) | (3,812) | (7,374) | (10,975) | |||||||||||||||
(Loss) Income Before Income Taxes | (31,580) | (23,643) | (65,315) | (88,958) | (120,538) | |||||||||||||||
Net (Loss) Income | $ (31,580) | $ (23,643) | $ (65,315) | $ (88,958) | $ (120,538) | |||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (0.95) | $ (0.71) | $ (1.97) | $ (2.68) | $ (3.63) | |||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | |||||||||||||||
Adjustment | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ (1,294) | $ 304 | $ 172 | $ 476 | $ (818) | |||||||||||||||
Total Revenues | (1,294) | 304 | 172 | 476 | (818) | |||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | (1,681) | 2,110 | 429 | 429 | ||||||||||||||||
Depreciation, depletion and amortization | 65 | 24 | (110) | (86) | (21) | |||||||||||||||
Accretion of asset retirement obligations | (139) | (66) | 684 | 618 | 479 | |||||||||||||||
Impairment of oil and natural gas properties | 2,357 | 848 | (3,280) | (2,432) | (75) | |||||||||||||||
Reorganization items | 3,773 | 3,773 | 3,773 | |||||||||||||||||
Total Costs and Expenses | 2,283 | 2,898 | (596) | 2,302 | 4,585 | |||||||||||||||
Operating Loss | (3,577) | (2,594) | 768 | (1,826) | (5,403) | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
(Loss) Income Before Income Taxes | (3,577) | (2,594) | 768 | (1,826) | (5,403) | |||||||||||||||
Net (Loss) Income | $ (3,577) | $ (2,594) | $ 768 | $ (1,826) | $ (5,403) | |||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (0.11) | $ (0.08) | $ 0.02 | $ (0.05) | $ (0.16) | |||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic and Diluted (in shares) | 33,241 | 33,237 | 33,228 | 33,234 | 33,236 | |||||||||||||||
Predecessor | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ 123,084 | $ 256,050 | $ 532,505 | |||||||||||||||||
Natural gas liquids sales | 2,144 | 3,533 | 14,852 | |||||||||||||||||
Natural gas sales | 17,735 | 37,103 | 69,255 | |||||||||||||||||
(Loss) Gain on derivative financial instruments | 90,506 | |||||||||||||||||||
Total Revenues | $ 153,723 | 142,963 | 296,686 | 707,118 | ||||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 65,170 | 136,578 | 328,183 | |||||||||||||||||
Production taxes | 214 | 482 | 1,442 | |||||||||||||||||
Gathering and transportation | 7,534 | 5,910 | 33,156 | |||||||||||||||||
Pipeline facility fee | 10,165 | 20,330 | 40,659 | |||||||||||||||||
Depreciation, depletion and amortization | 31,141 | 60,202 | 339,539 | |||||||||||||||||
Accretion of asset retirement obligations | 19,075 | 38,380 | 64,708 | |||||||||||||||||
Impairment of oil and natural gas properties | 77,558 | 77,781 | 2,814,028 | |||||||||||||||||
General and administrative expense | 15,435 | 27,557 | 102,736 | |||||||||||||||||
Total Costs and Expenses | 226,292 | 367,220 | 3,724,451 | |||||||||||||||||
Operating Loss | 12,795 | (83,329) | (70,534) | (3,017,333) | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 62 | 117 | 3,596 | |||||||||||||||||
Interest expense | (4,838) | (12,580) | (405,658) | |||||||||||||||||
Total Other (Expense) Income, net | (4,776) | (12,463) | 1,112,788 | |||||||||||||||||
Loss Before Reorganization Items and Income Taxes | (88,105) | (82,997) | (1,904,545) | |||||||||||||||||
Reorganization items | (32,633) | 2,733,608 | (14,201) | |||||||||||||||||
(Loss) Income Before Income Taxes | (120,738) | 2,650,611 | (1,918,746) | |||||||||||||||||
Income Tax Benefit | (87) | |||||||||||||||||||
Net (Loss) Income | $ 2,771,349 | $ (120,738) | $ 2,650,611 | $ (1,918,659) | ||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (1.23) | $ (20.08) | ||||||||||||||||||
Basic (in dollars per share) | $ 28.04 | $ 26.95 | ||||||||||||||||||
Diluted (in dollars per share) | $ 26.45 | $ 25.30 | ||||||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 98,850 | 98,337 | ||||||||||||||||||
Diluted (in shares) | 104,787 | 104,787 | ||||||||||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 | ||||||||||||||||||
Predecessor | As reported | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ 122,732 | $ 255,040 | $ 531,914 | |||||||||||||||||
Natural gas liquids sales | 2,144 | 3,533 | 14,852 | |||||||||||||||||
Natural gas sales | 17,735 | 37,103 | 69,255 | |||||||||||||||||
(Loss) Gain on derivative financial instruments | 90,506 | |||||||||||||||||||
Total Revenues | $ 153,065 | 142,611 | 295,676 | 706,527 | ||||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | 65,170 | 137,007 | 328,183 | |||||||||||||||||
Production taxes | 214 | 482 | 1,442 | |||||||||||||||||
Gathering and transportation | 7,534 | 5,910 | 33,156 | |||||||||||||||||
Pipeline facility fee | 10,165 | 20,330 | 40,659 | |||||||||||||||||
Depreciation, depletion and amortization | 31,573 | 60,626 | 339,516 | |||||||||||||||||
Accretion of asset retirement obligations | 19,437 | 38,973 | 64,690 | |||||||||||||||||
Impairment of oil and natural gas properties | 86,820 | 86,820 | 2,813,570 | |||||||||||||||||
General and administrative expense | 15,435 | 27,557 | 102,736 | |||||||||||||||||
Total Costs and Expenses | 236,348 | 377,705 | 3,723,952 | |||||||||||||||||
Operating Loss | 11,708 | (93,737) | (82,029) | (3,017,425) | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Other income, net | 62 | 117 | 3,596 | |||||||||||||||||
Interest expense | (4,838) | (12,580) | (405,658) | |||||||||||||||||
Total Other (Expense) Income, net | (4,776) | (12,463) | 1,112,788 | |||||||||||||||||
Loss Before Reorganization Items and Income Taxes | (98,513) | (94,492) | (1,904,637) | |||||||||||||||||
Reorganization items | (32,633) | 2,748,395 | (14,201) | |||||||||||||||||
(Loss) Income Before Income Taxes | (131,146) | 2,653,903 | (1,918,838) | |||||||||||||||||
Income Tax Benefit | (87) | |||||||||||||||||||
Net (Loss) Income | $ 2,785,049 | $ (131,146) | $ 2,653,903 | $ (1,918,751) | ||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ (1.34) | $ (20.11) | ||||||||||||||||||
Basic (in dollars per share) | $ 28.17 | $ 26.99 | ||||||||||||||||||
Diluted (in dollars per share) | $ 26.58 | $ 25.33 | ||||||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 98,850 | 98,337 | ||||||||||||||||||
Diluted (in shares) | 104,787 | 104,787 | ||||||||||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 | ||||||||||||||||||
Predecessor | Adjustment | ||||||||||||||||||||
Revenues | ||||||||||||||||||||
Oil sales | $ 352 | $ 1,010 | $ 591 | |||||||||||||||||
Total Revenues | $ 658 | 352 | 1,010 | 591 | ||||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Lease operating | (429) | |||||||||||||||||||
Depreciation, depletion and amortization | (432) | (424) | 23 | |||||||||||||||||
Accretion of asset retirement obligations | (362) | (593) | 18 | |||||||||||||||||
Impairment of oil and natural gas properties | (9,262) | (9,039) | 458 | |||||||||||||||||
Total Costs and Expenses | (10,056) | (10,485) | 499 | |||||||||||||||||
Operating Loss | 1,087 | 10,408 | 11,495 | 92 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Loss Before Reorganization Items and Income Taxes | 10,408 | 11,495 | 92 | |||||||||||||||||
Reorganization items | (14,787) | |||||||||||||||||||
(Loss) Income Before Income Taxes | 10,408 | (3,292) | 92 | |||||||||||||||||
Net (Loss) Income | $ (13,700) | $ 10,408 | $ (3,292) | $ 92 | ||||||||||||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||||||
Basic and Diluted (in dollars per share) | $ 0.11 | $ 0.03 | ||||||||||||||||||
Basic (in dollars per share) | $ (0.14) | $ (0.04) | ||||||||||||||||||
Diluted (in dollars per share) | $ (0.13) | $ (0.03) | ||||||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||
Basic (in shares) | 98,850 | 98,337 | ||||||||||||||||||
Diluted (in shares) | 104,787 | 104,787 | ||||||||||||||||||
Basic and Diluted (in shares) | 97,824 | 95,822 |
Supplementary Oil and Gas In150
Supplementary Oil and Gas Information – Unaudited - Costs incurred for oil and natural gas property (Details) $ in Thousands | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016USD ($)MMBoe | Dec. 31, 2017USD ($)MMBoe | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($)MMBoe | Jun. 30, 2014MMBoe | |
Property acquisitions | |||||
Proved | $ 96 | ||||
Exploration costs | 669 | ||||
Development costs | $ 62,283 | ||||
Proved Undeveloped Reserves (Energy) | MMBoe | 36,498 | 22,039 | |||
Future development costs associated with proved undeveloped reserves | $ 443,200 | $ 356,100 | |||
Predecessor | |||||
Property acquisitions | |||||
Proved | 1,500 | $ 26,400 | |||
Unevaluated | $ 2,304 | ||||
Exploration costs | 1,400 | 38,183 | |||
Development costs | $ 22,300 | $ 57,400 | $ 608,605 | ||
Proved Undeveloped Reserves (Energy) | MMBoe | 58,151 | 96,256 |
Supplementary Oil and Gas In151
Supplementary Oil and Gas Information – Unaudited - Estimated quantities and changes in quantities of proved reserves (Details) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Dec. 31, 2016USD ($)MMBoeMMcfMBbls | Dec. 31, 2017USD ($)MMBoeMMcfMBbls | Jun. 30, 2016MMBoeMMcfMBbls | Jun. 30, 2015MMBoeMMcfMBbls | Jun. 30, 2014MMBoeMMcfMBbls | |
Reserves | |||||
Proved reserves, beginning balance (Energy) | MMBoe | 121,937 | ||||
Production (Energy) | MMBoe | (12,493) | ||||
Extensions, discoveries and other additions (Energy) | MMBoe | 7,082 | ||||
Revisions of previous estimates (Energy) | MMBoe | (28,327) | ||||
Proved reserves, ending balance (Energy) | MMBoe | 121,937 | 88,199 | |||
Proved developed reserves (Energy) | MMBoe | 85,439 | 66,160 | |||
Proved undeveloped reserves (Energy) | MMBoe | 36,498 | 22,039 | |||
Decrease in proved reserves (in MMBOE) | MMBoe | 33.7 | ||||
Increase in proved reserves (as a percent) | 28.00% | ||||
Future development costs associated with proved undeveloped reserves | $ | $ 443.2 | $ 356.1 | |||
Proved Developed Nonproducing Reserves | |||||
Reserves | |||||
Negative revisions (Energy) | MMBoe | 9.6 | ||||
Oil Reserves | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | 95,250 | ||||
Production (Volume) | (9,324) | ||||
Extensions, discoveries and other additions (Volume) | 5,691 | ||||
Revisions of previous estimates (Volume) | (17,261) | ||||
Proved reserves, ending balance (Volume) | 95,250 | 74,356 | |||
Proved developed reserves (Volume) | 63,728 | 55,005 | |||
Proved undeveloped reserves (Volume) | 31,522 | 19,351 | |||
Natural Gas Liquids | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | 3,148 | ||||
Production (Volume) | (288) | ||||
Extensions, discoveries and other additions (Volume) | 217 | ||||
Revisions of previous estimates (Volume) | (1,397) | ||||
Proved reserves, ending balance (Volume) | 3,148 | 1,680 | |||
Proved developed reserves (Volume) | 2,777 | 1,335 | |||
Proved undeveloped reserves (Volume) | 371 | 345 | |||
Natural Gas Reserves | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | MMcf | 141,238 | ||||
Production (Volume) | MMcf | (17,282) | ||||
Extensions, discoveries and other additions (Volume) | MMcf | 7,030 | ||||
Revisions of previous estimates (Volume) | MMcf | (58,001) | ||||
Proved reserves, ending balance (Volume) | MMcf | 141,238 | 72,985 | |||
Proved developed reserves (Volume) | MMcf | 113,603 | 58,918 | |||
Proved undeveloped reserves (Volume) | MMcf | 27,635 | 14,067 | |||
Predecessor | |||||
Reserves | |||||
Proved reserves, beginning balance (Energy) | MMBoe | 86,564 | 183,496 | 246,198 | ||
Production (Energy) | MMBoe | (7,897) | (19,209) | (21,504) | ||
Extensions, discoveries and other additions (Energy) | MMBoe | 36,852 | 1,704 | 17,295 | ||
Revisions of previous estimates (Energy) | MMBoe | 6,418 | (91,031) | (46,333) | ||
Sales of reserves (Energy) | MMBoe | (12,160) | ||||
Purchases of reserves (Energy) | MMBoe | 11,604 | ||||
Proved reserves, ending balance (Energy) | MMBoe | 86,564 | 183,496 | |||
Proved developed reserves (Energy) | MMBoe | 86,564 | 125,345 | 149,942 | ||
Proved undeveloped reserves (Energy) | MMBoe | 58,151 | 96,256 | |||
Predecessor | Oil Reserves | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | 62,140 | 129,596 | 175,816 | ||
Production (Volume) | (5,482) | (12,624) | (14,272) | ||
Extensions, discoveries and other additions (Volume) | 31,846 | 1,370 | 10,056 | ||
Revisions of previous estimates (Volume) | 6,746 | (61,347) | (32,115) | ||
Sales of reserves (Volume) | (9,889) | ||||
Purchases of reserves (Volume) | 5,145 | ||||
Proved reserves, ending balance (Volume) | 62,140 | 129,596 | |||
Proved developed reserves (Volume) | 62,140 | 88,607 | 106,900 | ||
Proved undeveloped reserves (Volume) | 40,989 | 68,916 | |||
Predecessor | Natural Gas Liquids | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | 4,233 | 7,476 | 9,573 | ||
Production (Volume) | (167) | (923) | (987) | ||
Extensions, discoveries and other additions (Volume) | 375 | 46 | 517 | ||
Revisions of previous estimates (Volume) | (1,293) | (3,237) | (1,615) | ||
Sales of reserves (Volume) | (12) | ||||
Purchases of reserves (Volume) | 871 | ||||
Proved reserves, ending balance (Volume) | 4,233 | 7,476 | |||
Proved developed reserves (Volume) | 4,233 | 5,406 | 5,889 | ||
Proved undeveloped reserves (Volume) | 2,070 | 3,684 | |||
Predecessor | Natural Gas Reserves | |||||
Reserves | |||||
Proved reserves, beginning balance (Volume) | MMcf | 121,147 | 278,543 | 364,856 | ||
Production (Volume) | MMcf | (13,485) | (33,973) | (37,472) | ||
Extensions, discoveries and other additions (Volume) | MMcf | 27,788 | 1,729 | 40,330 | ||
Revisions of previous estimates (Volume) | MMcf | 5,788 | (158,681) | (75,617) | ||
Sales of reserves (Volume) | MMcf | (13,554) | ||||
Purchases of reserves (Volume) | MMcf | 33,529 | ||||
Proved reserves, ending balance (Volume) | MMcf | 121,147 | 278,543 | |||
Proved developed reserves (Volume) | MMcf | 121,147 | 187,993 | 222,916 | ||
Proved undeveloped reserves (Volume) | MMcf | 90,550 | 141,940 | |||
Reserve Revision Due To Change In Estimates Of Lease Operating Expenses | |||||
Reserves | |||||
Negative revisions (Energy) | MMBoe | 10.7 | ||||
Reserve Revision Due To Updated Technical Assessments Delayed Drilling Activity And Changes To Drilling Schedule | Proved Undeveloped Reserves | |||||
Reserves | |||||
Negative revisions (Energy) | MMBoe | 17.4 | ||||
Reserve Revision Due To Changes In Drilling Schedule Truncating Proved Economic Field Lives | Proved Developed Nonproducing Reserves | |||||
Reserves | |||||
Negative revisions (Energy) | MMBoe | 4.2 | ||||
Reserve Revision Due To Updated Technical Assessments | Proved Developed Nonproducing Reserves | |||||
Reserves | |||||
Negative revisions (Energy) | MMBoe | 5.2 | ||||
Reserve Revision Due To Increased Product Prices And Improved Field Economics | |||||
Reserves | |||||
Upward revisions (Energy) | MMBoe | 7 | ||||
Reserve Revision Due To Performance | Proved Developed Producing Reserves | |||||
Reserves | |||||
Upward revisions (Energy) | MMBoe | 3.3 |
Supplementary Oil and Gas In152
Supplementary Oil and Gas Information – Unaudited - Standardized measure of discounted future net cash flows - Average price (Details) | 12 Months Ended |
Dec. 31, 2017$ / MMBTU$ / bbl | |
Oil | |
Standardized Measure of Discounted Future Net Cash Flows | |
Average price used to compute future cash inflows (in dollars per unit) | 47.79 |
Average realized adjusted product price used to compute future net revenue (in dollars per unit) | 50.99 |
NGL | |
Standardized Measure of Discounted Future Net Cash Flows | |
Average realized adjusted product price used to compute future net revenue (in dollars per unit) | 26.79 |
Natural gas | |
Standardized Measure of Discounted Future Net Cash Flows | |
Average price used to compute future cash inflows (in dollars per unit) | $ / MMBTU | 2.98 |
Average realized adjusted product price used to compute future net revenue (in dollars per unit) | $ / MMBTU | 2.85 |
Supplementary Oil and Gas In153
Supplementary Oil and Gas Information – Unaudited - Schedule of standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Standardized Measure of Discounted Future Net Cash Flows | |||||
Future cash inflows | $ 4,044,208 | ||||
Production costs | 2,714,819 | ||||
Development and abandonment costs | 1,425,847 | ||||
Future net cash flows | (96,458) | ||||
Less: Ten percent annual discount for estimated timing of cash flows | (111,594) | ||||
Standardized measure of discounted future net cash flows | $ 15,136 | $ 148,845 | |||
Predecessor | |||||
Standardized Measure of Discounted Future Net Cash Flows | |||||
Future cash inflows | 4,344,985 | $ 2,966,317 | $ 10,641,151 | ||
Production costs | 2,648,363 | 2,223,645 | 4,131,526 | ||
Development and abandonment costs | 1,571,271 | 1,033,717 | 1,970,526 | ||
Income taxes | 168,655 | ||||
Future net cash flows | 125,351 | (291,045) | 4,370,444 | ||
Less: Ten percent annual discount for estimated timing of cash flows | (23,494) | (349,398) | 1,613,034 | ||
Standardized measure of discounted future net cash flows | $ 148,845 | $ 58,353 | $ 2,757,410 | $ 5,947,525 |
Supplementary Oil and Gas In154
Supplementary Oil and Gas Information – Unaudited - Changes in standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2016 | Jun. 30, 2015 | |
Changes in Standardized Measure of Discounted Future Net Cash Flows | ||||
Beginning of period | $ 148,845 | |||
Changes in prices and costs | 252,357 | |||
Changes in quantities | (198,211) | |||
Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs | 8,908 | |||
Accretion of discount | 14,885 | |||
Sales, net of production and gathering and transportation costs | (224,976) | |||
Changes in rate of production and other | (22,862) | |||
Development costs incurred | 3,878 | |||
Changes in estimated future development and abandonment costs | 32,312 | |||
Net change | (133,709) | |||
End of period | $ 148,845 | 15,136 | ||
Predecessor | ||||
Changes in Standardized Measure of Discounted Future Net Cash Flows | ||||
Beginning of period | 58,353 | $ 148,845 | $ 2,757,410 | $ 5,947,525 |
Changes in prices and costs | (104,993) | (3,287,459) | (2,959,883) | |
Changes in quantities | 53,585 | (214,631) | (2,390,099) | |
Additions to proved reserves resulting from extensions, discoveries, other additions and improved recovery, less related costs | 325,892 | 26,911 | 201,234 | |
Purchases (sales) of reserves in place | 212,961 | (244,507) | ||
Accretion of discount | (893) | 215,297 | 760,175 | |
Sales, net of production and gathering and transportation costs | (131,947) | (212,581) | (676,949) | |
Net change in income taxes | 77,025 | 1,576,954 | ||
Changes in rate of production and other | (2,704) | 4,189 | (191,668) | |
Development costs incurred | 11,283 | 10,493 | 237,173 | |
Changes in estimated future development and abandonment costs | (59,731) | 468,738 | 497,455 | |
Net change | 90,492 | (2,699,057) | (3,190,115) | |
End of period | $ 148,845 | $ 58,353 | $ 2,757,410 |