Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Feb. 28, 2019 | Jun. 29, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | WTI | ||
Entity Registrant Name | W&T OFFSHORE INC | ||
Entity Central Index Key | 1,288,403 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Shell Company | false | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Common Stock, Shares Outstanding | 140,644,033 | ||
Entity Public Float | $ 659,712,000 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 33,293 | $ 99,058 |
Receivables: | ||
Oil and natural gas sales | 47,804 | 45,443 |
Joint interest, net | 14,634 | 19,754 |
Income taxes | 54,076 | 13,006 |
Total receivables | 116,514 | 78,203 |
Prepaid expenses and other assets (Note 1) | 76,406 | 13,419 |
Total current assets | 226,213 | 190,680 |
Oil and natural gas properties and other, net – at cost: (Note 1) | 515,421 | 579,016 |
Restricted deposits for asset retirement obligations | 15,685 | 25,394 |
Income tax receivables | 52,097 | |
Other assets (Note 1) | 91,547 | 60,393 |
Total assets | 848,866 | 907,580 |
Current liabilities: | ||
Accounts payable | 82,067 | 79,667 |
Undistributed oil and natural gas proceeds | 28,995 | 20,129 |
Advances from joint interest partners | 20,627 | 3,998 |
Asset retirement obligations | 24,994 | 23,613 |
Long-term debt | 22,925 | |
Accrued liabilities (Note 1) | 29,611 | 17,930 |
Total current liabilities | 186,294 | 168,262 |
Long-term debt: (Note 2) | ||
Principal | 646,000 | 889,790 |
Carrying value adjustments | (12,465) | 79,337 |
Long-term debt, less current portion – carrying value | 633,535 | 969,127 |
Asset retirement obligations, less current portion | 285,143 | 276,833 |
Other liabilities (Note 1) | 68,690 | 66,866 |
Commitments and contingencies (Note 18) | ||
Shareholders’ deficit: | ||
Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at December 31, 2018 and December 31, 2017 | ||
Common stock, $0.00001 par value; 200,000,000 shares authorized; 143,513,206 issued and 140,644,033 outstanding at December 31, 2018 and 141,960,462 issued and 139,091,289 outstanding at December 31, 2017 | 1 | 1 |
Additional paid-in capital | 545,705 | 545,820 |
Retained earnings (deficit) | (846,335) | (1,095,162) |
Treasury stock, at cost; 2,869,173 shares at December 31, 2018 and December 31, 2017 | (24,167) | (24,167) |
Total shareholders' equity (deficit) | (324,796) | (573,508) |
Total liabilities and shareholders' equity (deficit) | $ 848,866 | $ 907,580 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.00001 | $ 0.00001 |
Preferred stock, shares authorized | 20,000,000 | 20,000,000 |
Preferred stock, issued | 0 | 0 |
Common stock, par value | $ 0.00001 | $ 0.00001 |
Common stock, shares authorized | 200,000,000 | 200,000,000 |
Common stock, issued | 143,513,206 | 141,960,462 |
Common stock, outstanding | 140,644,033 | 139,091,289 |
Treasury stock, shares | 2,869,173 | 2,869,173 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues: | |||
Total revenues | $ 580,706 | $ 487,096 | $ 399,986 |
Operating costs and expenses: | |||
Lease operating expenses | 153,262 | 143,738 | 152,399 |
Production taxes | 1,832 | 1,740 | 1,889 |
Depreciation, depletion and amortization | 131,423 | 138,510 | 194,038 |
Asset retirement obligations accretion | 18,431 | 17,172 | 17,571 |
Ceiling test write-down of oil and natural gas properties | 0 | 0 | 279,063 |
General and administrative expenses | 60,147 | 59,744 | 59,740 |
Derivative (gain) loss | (53,798) | (4,199) | 2,926 |
Total costs and expenses | 333,679 | 377,146 | 730,554 |
Operating income (loss) | 247,027 | 109,950 | (330,568) |
Interest expense, net | 48,645 | 45,521 | 84,382 |
Gain on debt transactions | 47,109 | 7,811 | 123,923 |
Other (income) expense, net | (3,871) | 5,127 | 1,369 |
Income (loss) before income tax expense (benefit) | 249,362 | 67,113 | (292,396) |
Income tax expense (benefit) | 535 | (12,569) | (43,376) |
Net income (loss) | $ 248,827 | $ 79,682 | $ (249,020) |
Basic and diluted earnings (loss) per common share | $ 1.72 | $ 0.56 | $ (2.60) |
Oil | |||
Revenues: | |||
Total revenues | $ 438,798 | $ 340,010 | $ 268,950 |
NGLs | |||
Revenues: | |||
Total revenues | 37,127 | 32,257 | 26,429 |
Natural gas | |||
Revenues: | |||
Total revenues | 99,629 | 108,923 | 100,405 |
Other | |||
Revenues: | |||
Total revenues | 5,152 | 5,906 | 4,202 |
Gathering and transportation | |||
Operating costs and expenses: | |||
Operating costs and expenses | $ 22,382 | $ 20,441 | $ 22,928 |
Consolidated Statements of Chan
Consolidated Statements of Changes In Shareholders' Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock Outstanding | Additional Paid-In Capital | Retained Earnings (Deficit) | Treasury Stock |
Beginning Balances at Dec. 31, 2015 | $ (526,491) | $ 1 | $ 423,499 | $ (925,824) | $ (24,167) |
Beginning Balances (in shares) at Dec. 31, 2015 | 76,506 | 2,869 | |||
Share-based compensation | 11,013 | 11,013 | |||
Stock issued, value | 106,366 | 106,366 | |||
Stock Issued, shares | 61,168 | ||||
RSUs and shares surrendered for payroll taxes, value | (905) | (905) | |||
Net income (loss) | (249,020) | (249,020) | |||
Ending Balances at Dec. 31, 2016 | (659,037) | $ 1 | 539,973 | (1,174,844) | $ (24,167) |
Ending Balances (in shares) at Dec. 31, 2016 | 137,674 | 2,869 | |||
Share-based compensation | 7,191 | 7,191 | |||
Stock Issued, shares | 1,417 | ||||
RSUs and shares surrendered for payroll taxes, value | (1,344) | (1,344) | |||
Net income (loss) | 79,682 | 79,682 | |||
Ending Balances at Dec. 31, 2017 | (573,508) | $ 1 | 545,820 | (1,095,162) | $ (24,167) |
Ending Balances (in shares) at Dec. 31, 2017 | 139,091 | 2,869 | |||
Share-based compensation | 3,540 | 3,540 | |||
Stock Issued, shares | 1,553 | ||||
RSUs and shares surrendered for payroll taxes, value | (3,655) | (3,655) | |||
Net income (loss) | 248,827 | 248,827 | |||
Ending Balances at Dec. 31, 2018 | $ (324,796) | $ 1 | $ 545,705 | $ (846,335) | $ (24,167) |
Ending Balances (in shares) at Dec. 31, 2018 | 140,644 | 2,869 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities: | |||
Net income (loss) | $ 248,827 | $ 79,682 | $ (249,020) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 149,854 | 155,682 | 211,609 |
Ceiling test write-down of oil and natural gas properties | 0 | 0 | 279,063 |
Gain on debt transactions | (47,109) | (7,811) | (123,923) |
Amortization and write-offs of debt items | 2,850 | 1,715 | 2,548 |
Share-based compensation | 3,540 | 7,191 | 11,013 |
Derivative (gain) loss | (53,798) | (4,199) | 2,926 |
Derivatives cash (payments) receipts, net | (28,164) | 4,199 | 4,746 |
Deferred income taxes | 500 | 217 | 28,392 |
Changes in operating assets and liabilities: | |||
Oil and natural gas receivables | (2,361) | (2,370) | (7,005) |
Joint interest receivables | 5,120 | 2,131 | 12 |
Insurance reimbursements | 31,740 | ||
Income taxes | 11,028 | (1,063) | (64,274) |
Prepaid expenses and other assets | 3,383 | 3,238 | (14,946) |
Escrow deposit - Apache lawsuit | (49,500) | ||
Asset retirement obligation settlements | (28,617) | (72,409) | (72,320) |
Cash advances from JV partners | 16,629 | (437) | 4,420 |
Accounts payable, accrued liabilities and other | 40,081 | 11,402 | 939 |
Net cash provided by operating activities | 321,763 | 159,408 | 14,180 |
Investing activities: | |||
Investment in oil and natural gas properties and equipment | (106,191) | (106,174) | (83,800) |
Acquisition of property interest | (16,782) | ||
Proceeds from sales of assets, net | 56,588 | 1,500 | |
Purchases of furniture, fixtures and other | (933) | (96) | |
Net cash used in investing activities | (66,385) | (107,107) | (82,396) |
Financing activities: | |||
Borrowings on credit facility | 61,000 | 340,000 | |
Repayments on credit facility | (40,000) | (340,000) | |
Extinguishment of debt – principal | (903,194) | ||
Extinguishment of debt – premiums | (21,850) | ||
Debt transactions costs | (17,457) | (421) | (18,464) |
Other | (3,622) | (1,295) | (928) |
Net cash (used in) provided by financing activities | (321,143) | (23,479) | 53,038 |
(Decrease) increase in cash and cash equivalents | (65,765) | 28,822 | (15,178) |
Cash and cash equivalents, beginning of period | 99,058 | 70,236 | 85,414 |
Cash and cash equivalents, end of period | 33,293 | 99,058 | 70,236 |
11.00% 1.5 Lien Term Loan, Due November 2019 | |||
Financing activities: | |||
Issuance of Senior Second Lien Notes/Lien Term Loan | 75,000 | ||
Payment of interest | (6,623) | (8,227) | $ (2,570) |
9.75% Senior Second Lien Notes, Due November 2023 | |||
Financing activities: | |||
Issuance of Senior Second Lien Notes/Lien Term Loan | 625,000 | ||
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||
Financing activities: | |||
Payment of interest | (9,725) | (7,335) | |
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||
Financing activities: | |||
Payment of interest | $ (4,672) | $ (6,201) |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | 1. Significant Accounting Policies Operations W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer with substantially all of its operations in the Gulf of Mexico. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our 100% owned subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in Note 4. Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Use of Estimates The preparation of financial statements in conformity with 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 date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. Recent Events The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities improved in 2018 compared to the average realized prices in 2017. In October 2018, we substantially changed our capital structure through the issuance of secured senior notes, which when combined with cash on hand, funded the repurchasing and retirement, repayment or redemption of all of the prior debt instruments. This transaction reduced the amount of debt outstanding and extended debt maturities with the new debt instruments maturing on November 1, 2023. In addition, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), which matures on October 18, 2022 and increased the borrowing base from $150.0 million to $250.0 million. See Note 2 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate liquidity to fund our operations through February 2020, the period of assessment to qualify as a going concern. However, we cannot predict the potential changes in commodity prices, which could affect our operations, liquidity levels and compliance with debt obligations. Reclassification Certain reclassifications have been made to prior periods’ financial statements to conform to the current year presentation as follows: In the Consolidated Statements of Operations, interest income was reclassified from Other (income) expense, net Interest expense, net Interest expense, net Net income (loss) before income tax expense (benefit) Net cash provided by operating activities Net cash used in investing activities Accounting Standard Updates Effective January 1, 2018 Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018. The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business. In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business. Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us as Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. Revenue Recognition We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied. Our contracts with customers are primarily short-term (less than 12 months). Our responsibilities to deliver a unit of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials. We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production. At December 31, 2018 and 2017, $4.1 million and $4.7 million, respectively, were included in current liabilities related to natural gas imbalances. Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies, large financial institutions and large trading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when considered necessary. The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas: Year Ended December 31, 2018 2017 2016 Customer Shell Trading (US) Co. 30 % 46 % 43 % BP Products North America 20 % ** ** Vitol Inc. 14 % 15 % 20 % ** Less than 10% We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts: 2018 2017 2016 Allowance for doubtful accounts, beginning of period $ 9,114 $ 7,602 $ 2,490 Additional provisions for the year 1,233 1,512 5,112 Uncollectable accounts written off (655 ) — — Allowance for doubtful accounts, end of period $ 9,692 $ 9,114 $ 7,602 Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 7 for additional information. Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets Year Ended December 31, 2018 2017 Derivatives – current (1) $ 60,687 $ — Prepaid/accrued insurance 2,987 2,401 Surety bonds unamortized premiums 2,210 2,676 Prepaid deposits related to royalties 8,872 6,456 Advances for capital expenditures 745 — Other 905 1,886 Prepaid expenses and other assets $ 76,406 $ 13,419 (1) Includes both open and closed contracts. Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and other, net Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. Oil and natural gas properties and equipment are recorded at cost using the full-cost method. Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2018 2017 Oil and natural gas properties and equipment $ 8,169,871 $ 8,102,044 Furniture, fixtures and other 20,228 21,831 Total property and equipment 8,190,099 8,123,875 Less accumulated depreciation, depletion and amortization 7,674,678 7,544,859 Oil and natural gas properties and other, net $ 515,421 $ 579,016 Ceiling Test Write-Down Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. We did not record a ceiling test write-down during 2018 or 2017. We recorded ceiling test write-downs in 2016, which was reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas. The ceiling test write-downs of the carrying value of our oil and natural gas properties was $279.1 million for 2016. If average crude oil and natural gas prices decrease significantly, it is possible that ceiling test write-downs could be recorded during 2019 or future periods. Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. See Note 6 for additional information. Oil and Natural Gas Reserve Information We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 20 for additional information about our proved reserves. Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2018 and 2017, and as of December 31, 2018, we had open commodity derivative instruments. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates. During 2018 and 2017, we did not enter into any derivative instruments related to interest rates. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. Whenever we have entered into derivative contracts, we did not designate our derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in earnings. Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes Other Assets (long-term) The major categories recorded in Other assets December 31, 2018 2017 Escrow deposit – Apache lawsuit $ 49,500 $ 49,500 Appeal bond deposits 6,925 6,925 Unamortized debt issuance costs 4,773 330 Investment in White Cap, LLC 2,586 2,511 Derivatives 21,275 — Unamortized brokerage fee for Monza 2,277 — Proportional consolidation of Monza's other assets (Note 4) 3,275 — Other 936 1,127 Total other assets $ 91,547 $ 60,393 Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2018 2017 Accrued interest $ 12,385 $ 4,200 Accrued salaries/payroll taxes/benefits 2,320 2,454 Incentive compensation plans 10,817 7,366 Litigation accruals 3,673 3,480 Other 416 430 Total accrued liabilities $ 29,611 $ 17,930 Debt Issued During 2016 We accounted for a debt exchange transaction in 2016, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring Debt Issuance Costs Debt issuance costs associated with our Credit Agreement are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our Credit Agreement is reported within Other Assets Long-term debt, less current portion – carrying value Premiums Received and Discounts Provided on Debt Issuance Premiums and discounts were recorded in Long-term debt, less current portion – carrying value Gain on Debt Transactions During 2018, the refinancing of our capital structure resulted in a gain of $47.1 million as a result of writing off the carrying value adjustments related to the debt issued in 2016, partially offset by premiums paid to repurchase and retire, repay or redeem all of our prior debt instruments. The gains recorded in 2017 and 2016 of $7.8 million and $123.9 million, respectively, relate to the debt exchange transaction occurring during 2016. Differences in the utilization of the payment-in-kind option during 2017 resulted in adjustments to the gain previously recorded in 2016. See Note 2 for additional information. Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2018 2017 Apache lawsuit $ 49,500 $ 49,500 Uncertain tax positions including interest/penalties 11,523 11,015 Dispute related to royalty deductions 4,787 — Dispute related to royalty-in-kind 2,135 914 Other 745 5,437 Total other liabilities (long-term) $ 68,690 $ 66,866 Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for additional information. Other (Income) Expense, Net For 2018, the amount consists of credits related to the de-recognition of certain liabilities that had exceeded the statute of limitations partially offset by expense related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program (as defined in Note 4). For 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. For 2016, the amount consists primarily of write-offs of debt issuance costs. Earnings (Loss) Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings (loss) per share under the two-class method when the effect is dilutive. See Note 14 for additional information. Recent Accounting Developments In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases Topic 842 In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses Topic 326 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 2. Long-Term Debt The components of our long-term debt are presented in the following tables (in thousands): December 31, 2018 December 31, 2017 Adjustments to Adjustments to Carrying Carrying Carrying Carrying Principal Value (1) Value Principal Value (2) Value Credit Facility, due October 2022 $ 21,000 $ — $ 21,000 $ — $ — $ — 9.75 % Senior Second Lien Notes, due November 2023: 625,000 (12,465 ) 612,535 — — — 11.00% 1.5 Lien Term Loan, due November 2019: — — — 75,000 15,596 90,596 9.00 % Second Lien Term Loan, due May 2020: — — — 300,000 (4,381 ) 295,619 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020: — — — 171,769 40,617 212,386 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021: — — — 153,192 50,005 203,197 8.50% Unsecured Senior Notes, due June 2019 — — — 189,829 425 190,254 Total long-term debt 646,000 (12,465 ) 633,535 889,790 102,262 992,052 Current maturities of long-term debt (3) — — — — 22,925 22,925 Long term debt, less current maturities $ 646,000 $ (12,465 ) $ 633,535 $ 889,790 $ 79,337 $ 969,127 (1) Unamortized debt issuance costs. (2) Unamortized debt issuance costs, unamortized debt premiums, unamortized debt discounts, future interest payments for certain debt instruments and future payments-in-kind (“PIK”) for certain debt instruments recorded on an undiscounted basis. (3) Future interest payments due within twelve months on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes (these debt instruments are defined below). Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2018 are as follows (in millions): 2019–$0.0; 2020–$0.0; 2021–$0.0; 2022–$21.0; 2023-$625.0. See below for a discussion of our debt instruments. 9.75% Senior Second Lien Notes Due 2023 On October 18, 2018, we entered into a series of transactions to effect a refinancing of substantially all of our outstanding indebtedness. At that time, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second Lien Notes”), which were issued at par with an interest rate of 9.75% per annum that matures on November 1, 2023, and are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”). The estimated annual effective interest rate on the Senior Second Lien Notes was 10.3%, which includes debt issuance costs. Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year, beginning on May 1, 2019. Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date. On and after November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.000% on November 1, 2022 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are guaranteed by Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). If we experience certain change of control events, we will be required to offer to repurchase the notes at 101.000% of the principal amount, plus accrued and unpaid interest, if any, to the repurchase date. Certain entities controlled by Tracy W. Krohn, Chairman, Chief Executive Officer and President of the Company, and his family were invested in certain existing notes of the Company that were repurchased by the Company in connection with the Refinancing Transaction (defined below). The Krohn entities tendered their existing notes on the same terms as were made available to all other holders of the existing notes pursuant to the publicly disclosed Company offer to purchase any and all such notes and reinvested an amount approximately equal to the proceeds from such tenders by purchasing approximately $8.0 million principal in Senior Second Lien Notes at the same price offered to other initial investors in the offering of such notes. As part of the 2018 Refinancing Transaction, the Krohn entities also had their previously disclosed $5.0 million investment in the Company’s Second Lien Term Loan (defined below) liquidated as the loan was repaid in full. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. The Senior Second Lien Notes contain covenants that limit or prohibit our ability and the ability of certain of our subsidiaries to: (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”). These covenants are subject to exceptions and qualifications set forth in the Indenture. In addition, most of the above described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Senior Second Lien Notes an investment grade rating and no default exists with respect to the Senior Second Lien Notes. Credit Agreement Concurrently with the issuance of the Senior Second Lien Notes, we entered into the Credit Agreement with a maturity date of October 18, 2022. The primary items of the Credit Agreement are as follows, with certain terms defined under the Credit Agreement: • The initial borrowing base and lending commitment is $250.0 million. • Letters of credit may be issued in amounts up to $30.0 million, provided availability under the Credit Agreement exists. • The Leverage Ratio, as defined in the Credit Agreement, is limited to 3.50 to 1.00 for quarters ending December 31, 2018 and March 31, 2019; 3.25 to 1.00 for quarters ending June 30, 2019 and September 30, 2019; and 3.00 to 1.00 for quarters ending December 31, 2019 and thereafter. In the event of a Material Acquisition, as defined in the Credit Agreement, the Leverage Ratio limit is 3.50 to 1.00 for the two quarters following a Material Acquisition. • The Current Ratio, as defined in the Credit Agreement, must be maintained at greater than 1.00 to 1.00. • We are required to have deposit accounts only with banks under the Credit Agreement with certain exceptions. • To the extent there are borrowings, the Applicable Margins, as defined in the Credit Agreement, for Eurodollar Loans range from 2.50% to 3.50% per annum and the Applicable Margins for ABR loans range from 1.50% to 2.50% per annum. The specific Applicable Margin rate is based on the Borrowing Base Utilization Percentage. • The commitment fee is 37.5 basis points if the Borrowing Base Utilization Percentage is below 50% and 50 basis points if the Borrowing Base Utilization Percentage is 50% or greater. • We were required to have derivative contracts for a minimum of 50% of projected production for 18 months based on existing proved developed producing reserves and certain other criteria by December 2, 2018 and have met this requirement. We may enter into derivative contracts with counter parties within the Credit Agreement or with other counter parties meeting certain criteria described in the Credit Agreement. Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on or before May 15 and November 14 each calendar year, and certain additional redeterminations that may be requested at the discretion of either the lenders or the Company. The borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement’s security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal property. As of December 31, 2018, we had $21.0 million borrowings outstanding under the Credit Agreement and as of December 31, 2017, we had no borrowings outstanding under the Fifth Amended and Restated Credit Agreement, as amended (the “Prior Credit Agreement). As of December 31, 2018 and 2017, we had $9.6 million and $0.3 million, respectively, outstanding in letters of credit under the Credit Agreement and Prior Credit Agreement, respectively. As of December 31, 2018, we were in compliance with all applicable covenants of the Credit Agreement and Senior Second Lien Notes. For information about fair value measurements of our long-term debt, refer to Note 3. Refinancing Transaction in 2018 On October 18, 2018, funds from the issuances of the Senior Second Lien Notes, borrowings under the Credit Agreement and cash on hand were used to repurchase and retire, repay or redeem all of the prior debt instruments, which are listed below. The issuance of the Senior Second Lien Notes, execution of the Credit Agreement and extinguishment of the prior debt instruments are collectively referred to as the “Refinancing Transaction”. A net gain of $47.1 million was recorded as a result of the Refinancing Transaction, comprised of the write off of carrying value adjustments of the prior debt instruments and partially offset by premiums paid. The effect on both basic and diluted earnings per share for 2018 was $0.33 per share, which assumes the gain would not affect our income tax expense for 2018. Prior Debt Instruments The following debt instruments were repurchased and retired, repaid or redeemed, including interest and applicable premiums as part of the Refinancing Transaction on October 18, 2018: • 11.00% 1.5 Lien Term Loan, (the “1.5 Lien Term Loan”) due November 15, 2019, $75.0 million principal outstanding on October 18, 2018. • 9.00% Term Loan, due May 15, 2020, $300.0 million principal outstanding on October 18, 2018. • 9.00%/10.75% Senior Second Lien PIK Toggle Notes (the “Second Lien PIK Toggle Notes”), due May 15, 2020, $177.5 million principal outstanding on October 18, 2018. • 8.50%/10.00% Senior Third Lien PIK Toggle Notes (the “Third Lien PIK Toggle Notes”), due June 15, 2021, $160.9 million principal outstanding on October 18, 2018. • 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, $189.8 million principal outstanding on October 18, 2018. Exchange Transaction in 2016 On September 7, 2016, we consummated a transaction whereby we exchanged approximately $710.2 million in aggregate principal amount, or 79%, of our Unsecured Senior Notes for: (i) $159.8 million in aggregate principal amount of Second Lien PIK Toggle Notes; (ii) $142.0 million in aggregate principal amount of Third Lien PIK Toggle Notes; and (iii) 60.4 million shares of our common stock (collectively, the “Debt Exchange”). At the same time on closing on the Debt Exchange, we closed on a $75.0 million, 1.5 Lien Term Loan, with the then largest holder of our Unsecured Senior Notes (collectively with the Debt Exchange, the “Exchange Transaction”). We accounted for the Exchange Transaction as a Troubled Debt Restructuring pursuant to the guidance under ASC 470-60. Under ASC 470-60, the carrying value of the Second Lien PIK Toggle Notes, Third Lien PIK Toggle Notes and 1.5 Lien Term Loan (the “2016 Debt”) was measured using all future undiscounted payments (principal and interest); therefore, no interest expense was recorded for the 2016 Debt in the Consolidated Statements of Operations from September 7, 2016 to October 18, 2018. Therefore, our reported interest expense was significantly less than the contractual interest payments for the period the 2016 Debt was outstanding. Under ASC 470-60, payments related to the 2016 Debt are reported in the financing section of the Condensed Consolidated Statements of Cash Flows. A gain of $123.9 million was recognized related to the Exchange Transaction during 2016. Under ASC 470-60, a gain was recognized as the sum of (i) the future undiscounted payments (principal and interest) related to the 2016 Debt, (ii) the fair value of the common stock issued and (iii) deal transaction costs of $18.9 million was less than the sum of (iv) the carrying value of the Unsecured Senior Notes exchanged and (v) the funds received from the 1.5 Lien Term Loan. The shares of common stock issued were valued at $1.76 per share, which was the closing price on September 7, 2016. The effect on both basic and diluted earnings per share for 2016 was $1.30 per share, which assumes the gain would not affect our income tax benefit for 2016. During the second quarter of 2017, interest on the Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes was paid in cash rather than in kind. As a result of the cash interest payment, an $8.2 million net reduction was recorded to long-term debt on the Consolidated Balance Sheet and the offset to Gain on Debt Transactions Gain on Debt Transactions |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 3. Fair Value Measurements Under GAAP, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk. 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 expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. The following table presents the fair value of our derivatives and long-term debt (in thousands): December 31, Hierarchy 2018 2017 Assets: Derivatives – open contracts Level 2 $ 74,580 $ — Liabilities: 9.75% Senior Second Lien Notes, due November 2023 Level 2 $ 546,875 $ — 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 — 75,000 9.00 % Second Lien Term Loan, due May 2020 Level 2 — 288,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 — 162,322 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 — 119,490 8.50% Unsecured Senior Notes, due June 2019 Level 2 — 178,439 Credit Agreement Level 2 21,000 — As of December 31, 2018, the carrying value of our open derivative contracts equaled the estimated fair value, and as of December 31, 2017, we did not have any open derivative contracts. We measure the fair value of our derivative contracts by applying the income approach using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative contracts are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices. The fair value of long-term debt is based on quoted prices, although the market is not an active market; therefore, the fair value is classified within Level 2. The carrying amount of debt under our Credit Agreement approximates fair value because the interest rates are variable and reflective of current market rates. The carrying value of our long-term debt is disclosed in Note 2 above. |
Joint Venture Drilling Program
Joint Venture Drilling Program | 12 Months Ended |
Dec. 31, 2018 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |
Joint Venture Drilling Program | 4. On March 12, 2018, W&T and two other initial members formed and initially funded a limited liability company, Monza Energy LLC, a Delaware limited liability company, that will jointly participate with us in the exploration, drilling and development of up to 14 identified drilling projects (the “JV Drilling Program”) in the Gulf of Mexico over the next three years. W&T initially contributed 88.94% of its working interest in 14 identified undeveloped drilling projects to Monza and retained 11.06% of its working interest. The Monza board approved the substitution of one of these identified undeveloped drilling projects, the Viosca Knoll 823 (“Virgo”) A-14 well, with the Virgo A-13 well, which was contributed to Monza through the conveyance by W&T of 58.71% of its working interest in such well to Monza and retaining 41.29% of its working interest in such well. The interest in the Virgo A-14 well was reconveyed to W&T. Since the initial closing, additional investors have joined as members of Monza and as of December 31, 2018, total commitments by all members, including W&T, were $361.4 million. Monza closed off funding from additional investors. The JV Drilling Program is structured so that we initially receive an aggregate of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our indirect interest through our interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases and providing access to available infrastructure at agreed upon rates. For one well in the JV Drilling Program, a modification was approved exempting W&T from funding certain cost overruns and W&T is receiving 20% of the revenues less expenses of its prior interest on a combined basis, which removes W&T’s promote in this well. W&T will be the operator of each well in the JV Drilling Program unless there is already a designated third-party operator. The members of Monza are made up of third-party investors, W&T and an entity owned and controlled by Mr. Tracy W. Krohn, our Chairman, Chief Executive Officer and President. The Krohn entity invested as a minority investor on the same terms and conditions as the third-party investors and its investment is limited to 4.5% of total invested capital within Monza. The entity affiliated with Mr. Krohn has made a capital commitment to Monza of $14.5 million. At the inception of Monza, W&T received a net reimbursement of approximately $20.0 million for the capital expenditures incurred prior to the close date for projects in the JV Drilling Program. W&T may be obligated to fund certain cost overruns, subject to certain exceptions, on JV Drilling Program wells above budgeted and contingency amounts. As of December 31, 2018, members of Monza made partner capital contribution payments to Monza totaling $114.7 million. Information on the structure and relationship follows: Board Structure and Authority Under the Monza limited liability agreement, the business and affairs of Monza are managed by a board of five directors, which will consist of three directors selected by the third-party investors, Mr. Krohn, and an additional independent director will be selected by a majority of the third-party investors in Monza subject to consent by W&T. The independent director and one of the directors to be selected by the investors have not yet been selected. The day-to-day operations of Monza are being managed by W&T, under the direction of the Monza board, pursuant to a services agreement. W&T has no control over the decisions of the Monza board. W&T has veto rights for certain decisions, but does not have the ability to unilaterally make decisions for Monza, except for day-to-day decisions as permitted under the services agreement. The Monza board is responsible for the management of Monza and for making decisions with respect to its interest in the 14 drilling projects, including approval of the budgets. Accounting Methodology and Carrying Amounts Our interest in Monza is considered to be a variable interest entity that we account for using proportional consolidation. We do not fully consolidate Monza because we are not considered the primary beneficiary and we utilize proportional consolidation to account for our interest in the Monza properties. As of December 31, 2018, in the Consolidated Balance Sheet, we recorded $8.8 million, net, in oil and natural gas properties, $3.3 million in other assets and $0.7 million, net, increase in working capital in connection with our proportional interest in Monza’s assets and liabilities. For the year ended December 31, 2018, we recorded $4.3 million in revenue, $2.3 million in operating expense and $0.2 million, net, in other expense in connection with our proportional interest in Monza’s operations. Maximum Exposure Our contribution to Monza as of December 31, 2018 was $53.0 million, which consisted of net cash and the conveyance of the Company’s working interest in the 14 projects. We may also take responsibility for certain drilling and completion cost overruns, subject to certain limitations and certain exceptions, of which the total exposure cannot be estimated at this time. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | 5. Acquisitions and Divestitures Heidelberg Field On April 5, 2018, we closed on the purchase from Cobalt International Energy, Inc. of a 9.375% non-operated working interest in the Heidelberg field located in Green Canyon blocks 859, 903 and 904. The gross purchase price was $31.1 million which was adjusted for certain closing items and an effective date of January 1, 2018. Cash flows generated by the acquired interest between the effective date and the closing date reduced the net purchase price to $16.8 million. We determined that the assets acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition. In connection with this transaction, we were required to furnish a letter of credit of $9.4 million to a pipeline company as consignee. We recognized ARO of $3.6 million as a component of the transaction. In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated commitment of $19.6 million as of the purchase date. Permian Basin On September 28, 2018, we closed on the divestiture of substantially all of our ownership in an overriding royalty interests in the Permian Basin. The net proceeds received were $56.6 million, which was recorded as a reduction to our full-cost pool. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 6. Asset Retirement Obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are required to be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using expected cash outflows associated with the ARO, discounted at our credit-adjusted risk-free rate when the liability is initially recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The following table is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2018 2017 Asset retirement obligations, beginning of period $ 300,446 $ 334,438 Liabilities settled (28,617 ) (72,409 ) Accretion of discount 18,431 17,172 Liabilities incurred and assumed through acquisition 4,286 163 Revisions of estimated liabilities (1) (2) 15,591 21,082 Asset retirement obligations, end of period 310,137 300,446 Less current portion 24,994 23,613 Long-term $ 285,143 $ 276,833 (1) Revisions in 2018 reflect cost estimate increases as a result of new data on the required scope of work becoming available to us through 2018. This new data included data realized during the planning phase of the projects, and as the projects proceeded through the execution phase. This new data indicated that the scope was larger and more difficult than the scope used for end of 2017 estimates. As an example, larger heavy lift vessels would be needed for certain platform removals, and certain wells needed additional well plugging operations to complete the decommissioning per agency requirements. (2) Revisions in 2017 were primarily related to increased costs associated with wells at four fields that experienced sustained casing pressure issues. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations. |
Insurance Claims
Insurance Claims | 12 Months Ended |
Dec. 31, 2018 | |
Insurance [Abstract] | |
Insurance Claims | 7. Insurance Claims During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority. During 2017 and 2016, we received insurance reimbursements of $31.7 million and $10.2 million, respectively, primarily related to hurricane damage. Cash receipts from insurance proceeds are included within Net cash provided by operating activities Oil and natural gas properties and other, net Lease operating expense General and administrative expenses Other income (expense), net |
Restricted Deposits
Restricted Deposits | 12 Months Ended |
Dec. 31, 2018 | |
Receivables [Abstract] | |
Restricted Deposits | 8. Restricted Deposits Restricted deposits as of December 31, 2018 and 2017 consisted of funds escrowed for collateral related to the future plugging and abandonment obligations of certain oil and natural gas properties. Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned to us once verification is made that the security amount requirements have been met. See Note 16 for potential future security requirements. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | 9. Our market risk exposure relates primarily to commodity prices and, from time to time, we use various derivative instruments to manage our exposure to this commodity price risk from sales of our oil and natural gas. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations. Additional collateral was not required by us and we do not require collateral from our derivative counterparties. Each derivative contract is recorded on the balance sheet as an asset or liability at fair value as of the respective period. We have elected not to designate our commodity derivative contracts as hedging instruments; therefore, all changes in the fair value of derivative contracts were recognized currently in earnings during the periods presented. While these contracts are intended to reduce the effects of price volatility, they may have limited incremental income from favorable price movements. Commodity Derivatives During 2018 and 2017, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected production for the time frames covered by the contracts. The crude oil contracts were based on West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”). The natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. The open contracts as of December 31, 2018 are presented in the following tables: Crude Oil: Swap, Priced off WTI (NYMEX) Termination Period Notional (1) Quantity (Bbls/day) Notional (1) Quantity (Bbls) Strike Price May 2020 1,500 775,500 $ 60.80 May 2020 5,000 2,585,000 61.00 May 2020 3,500 1,809,500 60.85 (1) Bbls = Barrels Crude Oil: Calls - Bought, Priced off WTI (NYMEX) Termination Period Notional (1) Quantity (Bbls/day) Notional (1) Quantity (Bbls) Strike Price May 2020 10,000 5,170,000 $ 61.00 (1) Bbls = Barrels Natural Gas: Two-way collars, Priced off Henry Hub (NYMEX) Termination Period Notional (2) Quantity (MMBtu/day) Notional (2) Quantity (MMBtu) Put Option Strike Price (Bought) Call Option Strike Price (Sold) June 2019 50,000 7,500,000 $ 2.49 $ 3.975 (2) MMBtu = Million British Thermal Units The following amounts were recorded in the Consolidated Balance Sheets in the categories presented and include the fair value of open contracts and closed contracts, which had not yet settled (in thousands): December 31, 2018 2017 Prepaid and other assets – current $ 60,687 $ — Other assets – non-current 21,275 — The amounts recorded on the Consolidated Balance Sheets are on a gross basis. If these were recorded on a net settlement basis, it would not have resulted in any differences in reported amounts. Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Year Ended December 31, 2018 2017 2016 Derivative (gain) loss $ (53,798 ) $ (4,199 ) $ 2,926 Cash (payments) receipts, net, on commodity derivative contract settlements, which include derivative premium payments, are included within Net cash provided by operating activities Year Ended December 31, 2018 2017 2016 Derivative cash (payments) receipts, net $ (28,164 ) $ 4,199 $ 4,746 |
Equity Transactions
Equity Transactions | 12 Months Ended |
Dec. 31, 2018 | |
Equity [Abstract] | |
Equity Transactions | 10. Equity Transactions During 2016, after receiving shareholder approval, the Company increased the amount of common stock authorized from 118.3 During 2018, 2017 and 2016, we did not pay any dividends and dividends are currently suspended. |
Share-Based Awards and Cash-Bas
Share-Based Awards and Cash-Based Awards | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Share-Based Awards and Cash-Based Awards | 11. Share-Based Awards and Cash-Based Awards Incentive Compensation Plan The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, and subsequent amendments, (the “Plan”) was approved by our shareholders. The Plan covers the Company’s eligible employees and consultants and includes both cash and share-based compensation awards. The Plan grants the Compensation Committee of the Board of Directors administrative authority over all participants, and grants the Chief Executive Officer (“CEO”) with authority over the administration of awards granted to participants that are not subject to section 16 of the Exchange Act (as applicable, the “Committee”). Pursuant to the terms of the Plan, the Committee establishes the vesting or performance criteria applicable to the award and may use a single measure or combination of business measures as described in the Plan. Also, individual goals may be established by the Committee. Performance awards may be granted in the form of stock options, stock appreciation rights, restricted stock, restricted stock units (“RSUs”), bonus stock, dividend equivalents, or other awards related to stock, and awards may be paid in cash, stock, or any combination of cash and stock, as determined by the Committee. The performance awards granted under the Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of performance award) will generally be paid within 90 days following the applicable year end. Share-based Awards: Restricted Stock Units During 2018, 2017 and 2016, the Company granted RSUs under the Plan to certain of its employees. RSUs are a long-term compensation component and are granted to certain employees, and are subject to satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period based on the results achieved. In addition to share-based awards, the Company may grant to its employees cash-based incentive awards under the Plan, which are both a short-term and long-term compensation components and are subject to satisfaction of certain predetermined performance criteria. As of December 31, 2018, there were 11,852,592 shares of common stock available for issuance in satisfaction of awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in shares of common stock, net of withholding tax. The Company has the option following vesting to settle RSUs in stock or cash, or a combination of stock and cash. During 2018, shares of common stock were used to settle all vested RSUs. During 2017, cash was used to settle vested RSUs related to the retirement of an executive officer and shares of common stock were used to settle all other vested RSUs. The Company expects to settle RSUs that vest in the future using shares of common stock. RSUs currently outstanding relate to the 2018 and 2017 grants, which were subject to predetermined performance criteria applied against the applicable performance period. These RSUs continue to be subject to employment-based criteria and vesting generally occurs in December of the second year after the grant. See the table below for anticipated vesting by year. We recognize compensation cost for share-based payments to employees over the period during which the recipient is required to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. The fair values for the RSUs granted during 2018, 2017 and 2016 were determined using the Company’s closing price on the grant date. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that are expected to actually vest. All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. During 2018, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) net income before income tax expense, net interest expense, depreciation, depletion, amortization, accretion and certain other items (“Adjusted EBITDA”) for 2018 and (ii) Adjusted EBITDA as a percent of total revenue (“Adjusted EBITDA Margin”) for 2018. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2018, the Company achieved target for both Adjusted EBITDA and Adjusted EBITDA Margin. During 2017, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2017 and (ii) Adjusted EBITDA Margin for 2017. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2017, the Company achieved target for both Adjusted EBITDA and Adjusted EBITDA Margin. During 2016, RSUs granted were subject to adjustments based on achievement of a combination of performance criteria, which was comprised of: (i) Adjusted EBITDA for 2016 and (ii) Adjusted EBITDA Margin for 2016. Adjustments range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2016, the Company was below target for Adjusted EBITDA and achieved target for Adjusted EBITDA Margin. A summary of activity related to RSUs is as follows: 2018 2017 2016 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 5,765,251 $ 2.48 6,107,248 $ 2.73 3,474,079 $ 7.42 Granted 988,955 6.90 2,128,879 2.76 4,213,964 2.21 Vested (2,261,665 ) 2.21 (2,108,553 ) 3.45 (968,652 ) 16.69 Forfeited (1,136,624 ) 2.68 (362,323 ) 2.87 (612,143 ) 3.64 Nonvested, end of period 3,355,917 $ 3.90 5,765,251 $ 2.48 6,107,248 $ 2.73 Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2018 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2019 2,429,006 2020 926,911 Total 3,355,917 RSUs fair value at grant date - During 2018, 2017 and 2016, the grant date fair value of RSUs granted was $6.8 million, $5.9 million and $9.3 million, respectively. RSUs fair value at vested date - The fair value of the RSUs that vested during 2018, 2017 and 2016 was $11.0 million, $5.5 million and $2.4 million, respectively, based on the Company’s closing price on the vesting date. Share-Based Awards: Restricted Stock Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2018, 2017 and 2016 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. The holders of Restricted Shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restriction period. As of December 31, 2018, there were 128,980 shares of common stock available for issuance in satisfaction of awards under the Directors Compensation Plan. Reductions in shares available are made when Restricted Shares are granted. A summary of activity related to Restricted Shares is as follows: 2018 2017 2016 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 246,528 $ 2.27 161,296 $ 3.47 78,230 $ 8.95 Granted 41,544 6.74 147,372 1.90 126,128 2.22 Vested (106,240 ) 2.64 (62,140 ) 4.51 (43,062 ) 9.75 Nonvested, end of period 181,832 $ 3.08 246,528 $ 2.27 161,296 $ 3.47 Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2018 are expected to vest as follows: Restricted Shares 2019 105,012 2020 62,972 2021 13,848 Total 181,832 Restricted stock fair value at grant date - The grant date fair value of restricted stock granted during 2018, 2017 and 2016 was $0.3 million each year for all years presented based on the Company’s closing price on the date of grant. Restricted stock fair value at vested date - The fair value of the restricted stock that vested during 2018, 2017 and 2016 was $0.7 million, $0.1 million and $0.1 million, respectively, based on the Company’s closing price on the date of vesting. Share-Based Compensation A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): Year Ended December 31, 2018 2017 2016 Share-based compensation expense from: Restricted stock units $ 3,260 $ 7,785 $ 10,640 Restricted stock 280 280 373 Total $ 3,540 $ 8,065 $ 11,013 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 743 $ 1,694 $ 3,855 As of December 31, 2018, unrecognized share-based compensation expense related to our awards of RSUs and Restricted Shares was $6.4 million and $0.4 million, respectively. Unrecognized compensation expense will be recognized through November 2020 for our RSUs and April 2021 for our Restricted Shares. Cash-based Awards In addition to share-based compensation, cash-based awards were granted under the Plan to substantially all eligible employees in 2018, 2017 and 2016. The cash-based awards, which are a short-term component of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. In addition, these cash-based awards included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred for any fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-based award. Expense is recognized over the service period once the business criteria, individual performance criteria and financial condition are met. • For the 2018 cash-based awards, a portion of the business criteria and individual performance criteria were achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2018 for a portion of the 2018 cash-based awards. Payments are expected to be made in March 2019 and are subject to all the terms of the 2018 Annual Incentive Award Agreement. • For the 2017 cash-based awards, a portion of the business criteria and individual performance criteria were achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense was recognized in 2017 and in the first quarter of 2018 for the 2017 cash-based awards. Payments were made in March 2018. • For the 2016 cash-based awards, the financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred exceeding $300 million over four consecutive quarters was not achieved by December 31, 2018; therefore no expense was recognized during 2018, 2017 or 2016. Share-Based Awards and Cash-Based Awards Compensation Expense A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2018 2017 2016 Share-based compensation included in: General and administrative $ 3,540 $ 8,065 $ 11,013 Cash-based incentive compensation included in: Lease operating expense 3,596 2,101 — General and administrative 9,586 5,032 — Total charged to operating income $ 16,722 $ 15,198 $ 11,013 |
Employee Benefit Plan
Employee Benefit Plan | 12 Months Ended |
Dec. 31, 2018 | |
Compensation And Retirement Disclosure [Abstract] | |
Employee Benefit Plan | 12. Employee Benefit Plan We maintain a defined contribution benefit plan (the “401(k) Plan”) in compliance with Section 401(k) of the Internal Revenue Code (“IRC”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. From March 5, 2016 to March 1, 2017, the Company suspended matching contributions. During the time periods where matching occurred, the Company’s matching contribution was 100% of each participant’s contribution up to a maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100% vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Our expenses relating to the 401(k) Plan were $2.0 million, $1.4 million and $0.4 million for 2018, 2017 and 2016, respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 13. Income Taxes Income Tax Expense (Benefit) Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2018 2017 2016 Current $ 35 $ (12,786 ) $ (71,768 ) Deferred 500 217 28,392 Total income tax expense (benefit) $ 535 $ (12,569 ) $ (43,376 ) Effective Tax Rate Reconciliation The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands, except percentages): Year Ended December 31, 2018 2017 2016 Income tax expense (benefit) at the federal statutory rate $ 52,366 21.0 % $ 23,490 35.0 % $ (102,339 ) 35.0 % Compensation adjustments 457 0.2 664 1.0 4,920 (1.7 ) State income taxes 560 0.2 63 0.1 (755 ) 0.2 Debt restructuring cost — — 18 — 1,463 (0.5 ) Impact of U.S. tax reform 487 0.2 105,933 157.8 — — Gain on exchange of debt — — (24,981 ) (37.2 ) — — Valuation allowance (53,980 ) (21.7 ) (118,643 ) (176.8 ) 52,915 (18.1 ) Other 645 0.3 887 1.4 420 (0.1 ) Total income tax expense (benefit) $ 535 0.2 % $ (12,569 ) (18.7 %) $ (43,376 ) 14.8 % Our effective tax rate for the years 2018, 2017 and 2016 differed from the applicable federal statutory rate of 21.0% for 2018 and 35.0% for 2017 and 2016 primarily due to recording and adjusting a valuation allowance for our deferred tax assets, which is discussed below. Deferred Tax Assets and Liabilities Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): December 31, 2018 2017 Deferred tax liabilities: Derivatives $ 11,139 $ — Investment in non-consolidated entity 6,875 — Other 812 695 Total deferred tax liabilities 18,826 695 Deferred tax assets: Property and equipment 3,934 18,234 Asset retirement obligations 65,811 63,755 Federal net operating losses 10,039 18,988 State net operating losses 7,133 7,126 Interest expense carryover 41,814 — Exchange transaction — 55,807 Share-based compensation 583 1,335 Valuation allowance (117,764 ) (171,547 ) Other 7,091 6,805 Total deferred tax assets 18,641 503 Net deferred tax liabilities $ (185 ) $ (192 ) During 2018, we received refunds of $11.1 million and made income tax payments of $0.1 million. During 2017, we received refunds of $11.9 million and made income tax payments of $0.2 million. During 2016, we received $7.8 million of refunds and Income Taxes Receivable As of December 31, 2018, we have current income taxes receivable of $54.1 million which primarily relates to our NOL carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years. These carryback claims were made pursuant to IRC Section 172 (f), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried back 10 years. The refund claims require a review by the Congressional Joint Committee on Taxation. Net Operating Loss, Interest and Tax Credit Carryovers The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2018 (in thousands): Amount Expiration Year Federal net operating loss $ 47,804 N/A State net operating losses 117,835 2025-2036 Interest limitation carryover 197,049 N/A Valuation Allowance During 2018 and 2017, we recorded a decrease in the valuation allowance of $53.8 million and $118.6 million, respectively, related to federal and state deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. As of December 31, 2018 and 2017, we had a valuation allowance related to our federal and state deferred tax asset. On December 22, 2017, the Tax Cuts and Jobs Act (“TCJA”) was enacted into law and we applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects of the TCJA in 2018 and 2017. As a result of the enactment of the TCJA, our net deferred tax assets and its respective valuation allowance were provisionally adjusted downwards by $105.9 million as of December 31, 2017. Our Consolidated Statement of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flow for the year 2017 were not materially impacted as a result of the provisional re-measurement of our net deferred tax assets and its related valuation allowance. At December 31, 2017, we had not completed our accounting for all of the enactment-date income tax effects of the TCJA under Accounting Standards Codification Topic 740, Income Taxes Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. Pending settlement of net operating loss carryback claims would require a change in our unrecognized tax benefits and materially impact on our effective tax rate if recognized. If recognized, our estimate of recognized tax benefits would be in the range of $11.5 million to $12.0 million. Balances in the uncertain tax positions are as follows (in thousands): December 31, 2018 2017 Balance, beginning and end of period $ 9,482 $ 9,482 We recognize interest and penalties related to uncertain tax positions in income tax expense. For 2018, 2017 and 2016, the amounts recognized in income tax expense were immaterial. Years open to examination The tax years from 2013 through 2018 remain open to examination by the tax jurisdictions to which we are subject. |
Earnings_ (Loss) Per Share
Earnings/ (Loss) Per Share | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings/ (Loss) Per Share | 14. Earnings (Loss) Per Share The Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings per share under the two-class method when the effect is dilutive. The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts): Year Ended December 31, 2018 2017 2016 Net income (loss) $ 248,827 $ 79,682 $ (249,020 ) Less portion allocated to nonvested shares 9,727 3,244 — Net income (loss) allocated to common shares $ 239,100 $ 76,438 $ (249,020 ) Weighted average common shares outstanding 139,002 137,617 95,644 Basic and diluted earnings (loss) per common share $ 1.72 $ 0.56 $ (2.60 ) Shares excluded due to being anti-dilutive (weighted-average) — — 5,269 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | 15. Supplemental Cash Flow Information The following table reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2018 2017 2016 Supplemental cash items: Cash paid for interest, net of interest capitalized of $0 in 2018, $0 in 2017 and $520 in 2016 (1) $ 61,501 $ 65,873 $ 96,501 Cash paid for income taxes 138 185 310 Cash refunds received for income taxes 11,126 11,906 7,796 Cash paid for share-based compensation (2) 1,130 874 — Cash received for interest income 2,385 315 7,889 Non-cash investing activities: Accruals of property and equipment 18,575 33,003 9,129 ARO - additions, dispositions and revisions, net 19,877 21,245 10,865 Non-cash financing activities: Exchange transaction – non-cash securities issued: 11.00% 1.5 Lien Term Loan - interest payable — — 23,823 9.00%/10.75% Second Lien PIK Toggle Notes – carrying value — — 223,905 8.50%/10.00% Third Lien PIK Toggle Notes – carrying value — — 213,446 Common stock issued - fair value at issuance date — — 106,366 Exchange transaction – non-cash securities exchanged: 8.50% Unsecured Senior Notes – carrying value — — (712,967 ) (1) During 2018, 2017 and 2016, cash paid for interest included amounts related to the debt issued during 2016, which were accounted for under ASC 470-60 and recorded against the carrying value of the debt instruments on the Consolidated Balance Sheets and included in financing activities (2) During 2018 and 2017, cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016, only common shares were used to settle vested RSUs and Restrict stock. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Commitments | 16. Commitments We have operating lease agreements for office space. The lease for our office space terminates in December 2022. Minimum future lease payments due under noncancelable operating leases with terms in excess of one year as of December 31, 2018 are as follows: 2019–$1.5 million; 2020–$1.6 million; 2021–$1.6 million; 2022–$1.6 million and thereafter–$0.0 million. Total rent expense was approximately $3.4 million, $3.0 million and $3.2 million during 2018, 2017 and 2016, respectively. Pursuant to the Purchase and Sale Agreement with Total E&P, we may fulfill security requirements related to ARO for certain properties through securing surety bonds, or through making payments to an escrow account under a formula pursuant to the agreement, or a combination thereof, until certain prescribed thresholds are met. Once the threshold is met for that year, excess funds in the escrow account are returned to us. As of December 31, 2018, we had surety bonds related to the agreement with Total E&P totaling $88.5 million and had no amounts in escrow. The threshold is $91.0 million for 2019 and escalates to $103.0 million for 2023 in $3.0 million per year increments. Pursuant to the Purchase and Sale Agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain properties, we have surety bonds that are subject to re-appraisal by either party. As of December 31, 2018, neither party had requested a re-appraisal to be made. The current security requirement of $64.0 million, which we have met and could be increased up to $94.0 million depending on certain conditions and circumstances. During 2018, 2017 and 2016, we had surety bonds primarily related to our decommissioning obligations or ARO. Total expenses related to surety bonds, inclusive of the surety bonds in connection with the Total E&P and Shell agreements described above, were $5.9 million, $5.7 million and $4.3 million during 2018, 2017 and 2016, respectively. The amount of future commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated future expenses related to surety bonds were based on current market prices and estimates of the timing of asset retirements, of which some wells and structures are estimated to extend to 2065. Future payment estimates are: 2019–$4.5 million; 2020–$4.2 As of December 31, 2018, we had $6.9 million of collateral deposits for certain sureties related to certain surety bonds for appeals submitted to the Interior Board of Land Appeals (the “IBLA”). In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline companies that contain minimum quantities obligations that extend to 2028. As of December 31, 2018, the estimated future costs are: 2019–$4.9 million; 2020–$4.0 million; 2021–$2.3 million; 2022–$1.7 million; 2023–$1.2 million; and thereafter–$2.0 million. We have no drilling rig commitments with a term that exceeded one year as of December 31, 2018 and our drilling rig commitments meet the criteria of an operating lease. Future payments of all drilling rig commitments as of December 31, 2018 were $9.7 million. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Parties | 17. Related Parties During 2018, 2017 and 2016, there were certain transactions between us and other companies our CEO either controlled or in which he had an ownership interest. In addition, there were transactions with a company that employs the spouse of our CEO. Our CEO owns an aircraft that the Company used and reimbursed him for such use and for his use pursuant to his employment contract. Airplane services transactions were approximately $1.3 million, $1.2 million and $1.1 million for the years 2018, 2017 and 2016, respectively. Our CEO has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage on certain wells were disbursed. A company that provides marine transportation and logistics services to W&T employs the spouse of our CEO. The rates charged for these marine and transportation services were either equal to or below rates charged by non-related, third-party companies. Payments to such company totaled $21.0 million, $22.8 million and $17.3 million in 2018, 2017 and 2016, respectively. The spouse received commissions partially based on services rendered to W&T which were approximately $0.2 million in 2018 and 2017 and less than $0.2 million for 2016. During 2018, an entity controlled by our CEO participated in the Senior Second Lien Note issuance for an $8.0 million principal commitment on the same terms as the other lenders. See Note 4 for information on a related party transaction concerning Monza. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Contingencies | 18. Contingencies Apache Lawsuit On December 15, 2014, Apache filed a lawsuit against the Company alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. A trial court judgment was rendered from the U.S. District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $43.2 million, plus $6.3 million in prejudgment interest, attorney's fees and costs assessed in the judgment. We filed an appeal of the trial court judgment in the U.S. Court of Appeals for the Fifth Circuit and provided oral arguments in December 2018. Prior to filing the appeal, in order to stay execution of the judgment, we deposited $49.5 million with the registry of the court in June 2017. Oral arguments occurred on December 4, 2018, but as of the filing date of this Form 10-K, a decision had not been rendered by the U.S. Court of Appeals for the Fifth Circuit. The deposit of $49.5 million with the registry of the U.S. Court of Appeals for the Fifth Circuit was recorded in Other assets Cash and cash equivalents Other liabilities Oil and natural gas properties and other, net Other (income) expense, net Appeal with ONRR In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR. We filed an appeal with the ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the IBLA under the Department of the Interior. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on March 27, 2017. Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S. District Court for the Eastern District of Louisiana. We were required to post a bond in the amount of $7.2 million and cash collateral of $6.9 million in order to appeal the IBLA decision. On December 4, 2018, the IBLA denied our motion for reconsideration. On February 4, 2019, we filed our first amended complaint. Royalties-In-Kind (“RIK”). Under a program of the Minerals Management Service (“MMS”) (a Department of Interior agency and predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program. The MMS added to the RIK program our lease at the East Cameron 373 field beginning in November 2001, where in some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for royalties owed. The MMS elected to terminate receiving royalties in-kind in October 2008 causing the imbalance to become fixed for accounting purposes. The MMS ordered us to pay an amount based on its interpretation of the program and its calculations of amounts owed. We disagreed with MMS’s interpretations and calculations and filed an appeal with the IBLA, of which the IBLA ruled in MMS’ favor. We filed an appeal with the District Court of the Western District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld the magistrate’s ruling on May 29, 2018. We filed an appeal on July 24, 2018. Part of the ruling was in favor of our position and part was in favor of MMS’ position. Based solely on the District Court’s ruling, we recorded a liability reserve of $2.1 million as of December 31, 2018. We have appealed the ruling to the U.S. Fifth Circuit Court of Appeals, and the government filed a cross-appeal. Briefing and oral arguments (if held) will be completed in 2019. Royalties – “Unbundling” Initiative The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR for additional data regarding our transportation and processing allowances on natural gas production related to a specific processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time periods to the ONRR. As of the filing date of this Form 10-K, we have not received a response from the ONRR related to our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. During 2018, 2017 and 2016, we paid $0.6 million, $1.6 million and $0.5 million, respectively, of additional royalties and expect to pay more in the future. We are not able to determine the range of any additional royalties or if such amounts would be material. Supplemental Bonding Requirements by the BOEM The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to assurance obligations. W&T and other offshore Gulf of Mexico producers may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurances. Surety Bond Issuers’ Collateral Requirements The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds for plugging and abandonment activities. We may be required to post collateral at any time pursuant to the terms of our agreement with various sureties under our existing bonds, if they so demand at their discretion. We did not receive any collateral demands from surety bond providers during 2018. Notices of Proposed Civil Penalty Assessment During 2018, we did not make any civil penalty payments and during 2017 and 2016, we paid $0.2 million and $0.1 million, respectively, in civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to Incidents of Noncompliance (“INCs”) issued by the BSEE at various offshore locations. We currently have nine open civil penalties issued by the BSEE arising from INCs, which have not been settled as of the filing of this Form 10-K. The INCs underlying these open civil penalties cite alleged non-compliance with various safety-related requirements and procedures occurring at separate offshore locations on various dates ranging from July 2012 to January 2018. The proposed civil penalties for these INCs total $7.7 million. As of December 31, 2018, we have accrued approximately $3.5 million in expenses, which is our best estimate of the final settlement once all appeals have been exhausted. Our position is that the proposed civil penalties are excessive given the specific facts and circumstances related to these INCs. Other Claims We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity. |
Selected Quarterly Financial Da
Selected Quarterly Financial Data | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data | 19. Selected Quarterly Financial Data—UNAUDITED Unaudited quarterly financial data are as follows (in thousands, except per share amounts): 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2018 Revenues $ 134,213 $ 149,612 $ 153,459 $ 143,422 Operating income 38,739 48,467 57,147 102,674 Net income (1) 27,640 36,083 46,260 138,844 Basic and diluted earnings per common share 0.19 0.25 0.32 0.96 Year Ended December 31, 2017 Revenues $ 124,393 $ 123,323 $ 110,281 $ 129,099 Operating income 28,196 32,888 15,700 33,166 Net income (loss) (1) 24,299 33,315 (1,297 ) 23,365 Basic and diluted earnings (loss) per common share 0.17 0.23 (0.01 ) 0.16 (1) During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. During the first quarter of 2017, we recorded a gain on debt transactions of $7.8 million. See Note 2 and Note 9 for additional information. (2) The sum of the individual quarterly earnings (loss) per common share may not agree with the yearly amount due to each quarterly calculation is based on income for that quarter and the weighted average common shares outstanding for that quarter. |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures-unaudited | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Gas Disclosures-UNAUDITED | 20. Supplemental Oil and Gas Disclosures—UNAUDITED Geographic Area of Operation All of our proved reserves are located within the United States in the Gulf of Mexico. Therefore, the following disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis. Capitalized Costs Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): December 31, 2018 2017 2016 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,169.9 $ 8,102.0 $ 7,932.5 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (7,665.1 ) (7,525.0 ) (7,387.8 ) Net capitalized costs related to producing activities $ 504.8 $ 577.0 $ 544.7 Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): Year Ended December 31, 2018 2017 2016 Costs incurred: (1) Proved properties acquisitions $ 24.1 $ 1.1 $ 1.3 Exploration (2) (3) 49.9 62.0 4.8 Development 56.2 92.5 56.9 Unproved properties acquisitions — — 0.5 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 130.2 $ 155.6 $ 63.5 (1) Includes net additions from capitalized ARO of $20.3 million, $21.3 million and $10.8 million during 2018, 2017 and 2016, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $1.5 million, $0.5 million and $0.2 million incurred during 2018, 2017 and 2016, respectively. (3) Includes geological and geophysical costs charged to expense of $5.4 million, $4.2 million and $4.1 million during 2018, 2017 and 2016, respectively. Depreciation, depletion, amortization and accretion expense The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold: Year Ended December 31, 2018 2017 2016 Depreciation, depletion, amortization and accretion per Boe $ 11.24 $ 10.68 $ 13.77 Oil and Natural Gas Reserve Information There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve information represents estimates only and are inherently imprecise and may be subject to substantial revisions as additional information such as reservoir performance, additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. We are not the operator with respect to approximately 13% of our proved developed non-producing reserves as of December 31, 2018 so we may not be in a position to control the timing of all development activities. We are the operator for substantially all of our proved undeveloped reserves as of December 31, 2018. In prior years, we were not the operator of substantially all proved undeveloped reserves. The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “ Standardized Measure of Discounted Future Net Cash Flows”. Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2015 35.5 6.6 205.4 76.4 458.1 Revisions of previous estimates (2) 4.6 3.1 32.1 13.0 78.1 Production (7.2 ) (1.5 ) (39.7 ) (15.4 ) (92.2 ) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Revisions of previous estimates (3) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (4) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Revisions of previous estimates (5) 11.6 2.8 40.4 21.1 126.7 Extensions and discoveries (6) 0.5 0.3 7.7 2.1 12.6 Purchase of minerals in place (7) 1.5 0.4 9.4 3.4 20.7 Sales of minerals in place (8) (2.2 ) (0.2 ) (7.2 ) (3.5 ) (21.2 ) Production (6.7 ) (1.3 ) (32.0 ) (13.3 ) (80.0 ) Proved reserves as of Dec. 31, 2018 39.1 9.8 210.5 84.0 504.1 Year-end proved developed reserves: 2018 31.5 7.8 166.8 67.0 402.2 2017 26.1 7.2 173.5 62.2 373.3 2016 26.6 7.6 183.1 64.7 388.2 Year-end proved undeveloped reserves: 2018 (9) 7.6 2.0 43.7 17.0 101.9 2017 8.3 0.6 18.7 12.0 72.0 2016 6.3 0.6 14.7 9.3 55.8 Volume measurements: MMBbls – million barrels for crude oil, condensate or NGLs Bcf – billion cubic feet MMBoe – million barrels of oil equivalent Bcfe – billion cubic feet of gas equivalent (1) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. (2) Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Virgo field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. (3) Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions. (4) Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. (5) Primarily related to upward revisions of 13.8 MMBoe at our Mahogany field and of 5.4 MMBoe at our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions. (6) Primarily related to extensions and discoveries of 1.3 MMBoe at our Virgo field and 0.7 MMBoe at our Ewing Bank 910 field. (7) Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg). (8) Primarily related to conveyance of interest in properties related to the JV Drilling Program. (9) We believe that we will be able to develop all but 1.8 MMBoe (approximately 11%) of the total of 17.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2018, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one in each field, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2021 and 2022, respectively. Standardized Measure of Discounted Future Net Cash Flows The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows: December 31, 2018 2017 2016 2015 Oil - per barrel $ 65.21 $ 46.58 $ 36.28 $ 46.94 NGLs per barrel 29.73 22.65 16.82 17.60 Natural gas per Mcf 3.13 2.86 2.47 2.50 Future production, development costs and ARO are based on costs in effect at the end of each of the respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on a 10% annual discount rate. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2019 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2018 2017 2016 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 3,500.9 $ 2,328.8 $ 1,818.4 Future costs: Production (958.5 ) (813.8 ) (691.5 ) Development (272.4 ) (157.4 ) (141.1 ) Dismantlement and abandonment (355.9 ) (361.9 ) (427.7 ) Income taxes (1) (293.9 ) (74.8 ) — Future net cash inflows before 10% discount 1,620.2 920.9 558.1 10% annual discount factor (553.2 ) (180.3 ) (79.8 ) Total $ 1,067.0 $ 740.6 $ 478.3 (1) No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality. The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2018 2017 2016 Changes in Standardized Measure Standardized measure, beginning of year $ 740.6 $ 478.3 $ 613.9 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (398.1 ) (315.3 ) (218.6 ) Net changes in price, net of future production costs 571.5 288.0 (275.2 ) Extensions and discoveries, net of future production and development costs 53.6 119.3 — Changes in estimated future development costs (114.7 ) (38.9 ) (32.5 ) Previously estimated development costs incurred 48.4 102.8 114.5 Revisions of quantity estimates 307.6 106.4 190.1 Accretion of discount 50.5 30.2 52.6 Net change in income taxes (133.4 ) (54.7 ) — Purchases of reserves in-place 27.8 — — Sales of reserves in-place (54.1 ) — — Changes in production rates due to timing and other (32.7 ) 24.5 33.5 Net increase (decrease) in standardized measure 326.4 262.3 (135.6 ) Standardized measure, end of year $ 1,067.0 $ 740.6 $ 478.3 |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Operations | Operations W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an independent oil and natural gas producer with substantially all of its operations in the Gulf of Mexico. We are active in the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent Company”) and our 100% owned subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in Note 4. |
Basis of Presentation | Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with 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 date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. |
Recent Events | Recent Events The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average realized prices of these commodities improved in 2018 compared to the average realized prices in 2017. In October 2018, we substantially changed our capital structure through the issuance of secured senior notes, which when combined with cash on hand, funded the repurchasing and retirement, repayment or redemption of all of the prior debt instruments. This transaction reduced the amount of debt outstanding and extended debt maturities with the new debt instruments maturing on November 1, 2023. In addition, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), which matures on October 18, 2022 and increased the borrowing base from $150.0 million to $250.0 million. See Note 2 for additional information. We have assessed our financial condition, the current capital markets and options given different scenarios of commodity prices. We believe we will have adequate liquidity to fund our operations through February 2020, the period of assessment to qualify as a going concern. However, we cannot predict the potential changes in commodity prices, which could affect our operations, liquidity levels and compliance with debt obligations. |
Reclassification | Reclassification Certain reclassifications have been made to prior periods’ financial statements to conform to the current year presentation as follows: In the Consolidated Statements of Operations, interest income was reclassified from Other (income) expense, net Interest expense, net Interest expense, net Net income (loss) before income tax expense (benefit) Net cash provided by operating activities Net cash used in investing activities |
Accounting Standard Updates Effective January 1, 2018 | Accounting Standard Updates Effective January 1, 2018 Accounting Standards Update No. 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business (“ASU 2017-01”), became effective for us as of January 1, 2018. The new guidance is intended to assist with the evaluation of whether a set of transferred assets and activities is a business. In application of the revised guidance under ASU 2017-01 for our acquisition of a non-operated interest in the Heidelberg field described in Note 5, we determined the transaction should be treated as an asset purchase rather than the purchase of a business. Accounting Standard Update No. 2014-09, Revenue from Customers (Topic 606) (“ASU 2014-09”), became effective for us as |
Cash Equivalents | Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. |
Revenue Recognition | Revenue Recognition We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are satisfied. Our contracts with customers are primarily short-term (less than 12 months). Our responsibilities to deliver a unit of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials. We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production. At December 31, 2018 and 2017, $4.1 million and $4.7 million, respectively, were included in current liabilities related to natural gas imbalances. |
Concentration of Credit Risk | Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies, large financial institutions and large trading houses. The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when considered necessary. The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas: Year Ended December 31, 2018 2017 2016 Customer Shell Trading (US) Co. 30 % 46 % 43 % BP Products North America 20 % ** ** Vitol Inc. 14 % 15 % 20 % ** Less than 10% We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. Accounts Receivables and Allowance for Bad Debts Our accounts receivables are recorded at their historical cost, less an allowance for doubtful accounts. The carrying value approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our production to our customers, we also have receivables from joint interest owners on properties we operate. In certain arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint interest partners. We have not had any significant problems collecting our receivables from our customers, but with the decline in commodity prices starting in 2015, several oil and gas companies have filed for bankruptcy where we have joint interest arrangements. We use the specific identification method of determining if an allowance for doubtful accounts is needed. The following table describes the balance and changes to the allowance for doubtful accounts: 2018 2017 2016 Allowance for doubtful accounts, beginning of period $ 9,114 $ 7,602 $ 2,490 Additional provisions for the year 1,233 1,512 5,112 Uncollectable accounts written off (655 ) — — Allowance for doubtful accounts, end of period $ 9,692 $ 9,114 $ 7,602 |
Insurance Receivables | Insurance Receivables We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs primarily as a result of hurricane damage when we deem those to be probable of collection, which normally arises when our insurance company’s adjuster reviews and approves such costs for payment or when the insurance company has agreed to reimbursement amounts. Claims that have been processed in this manner have customarily been paid on a timely basis. During 2017, we received payments by certain insurance companies related to settlement of previously unpaid claims. See Note 7 for additional information. |
Prepaid Expenses and Other Assets | Prepaid expenses and other assets Amounts recorded in Prepaid expenses and other assets Year Ended December 31, 2018 2017 Derivatives – current (1) $ 60,687 $ — Prepaid/accrued insurance 2,987 2,401 Surety bonds unamortized premiums 2,210 2,676 Prepaid deposits related to royalties 8,872 6,456 Advances for capital expenditures 745 — Other 905 1,886 Prepaid expenses and other assets $ 76,406 $ 13,419 (1) Includes both open and closed contracts. |
Properties and Equipment | Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as we have made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. We capitalize interest on the amount of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. Capitalization of interest ceases when the property is moved into the amortization base. All capitalized interest is recorded within Oil and natural gas property and other, net Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense. Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. Oil and natural gas properties and equipment are recorded at cost using the full-cost method. Oil and Natural Gas Properties and Other, Net – at cost Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2018 2017 Oil and natural gas properties and equipment $ 8,169,871 $ 8,102,044 Furniture, fixtures and other 20,228 21,831 Total property and equipment 8,190,099 8,123,875 Less accumulated depreciation, depletion and amortization 7,674,678 7,544,859 Oil and natural gas properties and other, net $ 515,421 $ 579,016 |
Ceiling Test Write-Down | Ceiling Test Write-Down Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately disclosed. Any such write downs are not recoverable or reversible in future periods. The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. We did not record a ceiling test write-down during 2018 or 2017. We recorded ceiling test write-downs in 2016, which was reported as a separate line in the Statements of Operations, due primarily to declines in the unweighted rolling 12-month average of first-day-of-the-month commodity prices for oil and natural gas. The ceiling test write-downs of the carrying value of our oil and natural gas properties was $279.1 million for 2016. If average crude oil and natural gas prices decrease significantly, it is possible that ceiling test write-downs could be recorded during 2019 or future periods. |
Asset Retirement Obligations | Asset Retirement Obligations We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. See Note 6 for additional information. |
Oil and Natural Gas Reserve Information | Oil and Natural Gas Reserve Information We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity prices. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 20 for additional information about our proved reserves. |
Derivative Financial Instruments | Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas. We do not enter into derivative instruments for speculative trading purposes. We entered into commodity derivatives contracts during 2018 and 2017, and as of December 31, 2018, we had open commodity derivative instruments. When we have outstanding borrowings on our revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest rate risk from floating interest rates. During 2018 and 2017, we did not enter into any derivative instruments related to interest rates. Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. Whenever we have entered into derivative contracts, we did not designate our derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in earnings. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value or it is required by applicable guidance. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. |
Income Taxes | Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes |
Other Assets (Long-term) | Other Assets (long-term) The major categories recorded in Other assets December 31, 2018 2017 Escrow deposit – Apache lawsuit $ 49,500 $ 49,500 Appeal bond deposits 6,925 6,925 Unamortized debt issuance costs 4,773 330 Investment in White Cap, LLC 2,586 2,511 Derivatives 21,275 — Unamortized brokerage fee for Monza 2,277 — Proportional consolidation of Monza's other assets (Note 4) 3,275 — Other 936 1,127 Total other assets $ 91,547 $ 60,393 |
Accrued Liabilities | Accrued Liabilities The major categories recorded in Accrued liabilities December 31, 2018 2017 Accrued interest $ 12,385 $ 4,200 Accrued salaries/payroll taxes/benefits 2,320 2,454 Incentive compensation plans 10,817 7,366 Litigation accruals 3,673 3,480 Other 416 430 Total accrued liabilities $ 29,611 $ 17,930 |
Debt Issued During 2016 | Debt Issued During 2016 We accounted for a debt exchange transaction in 2016, which is described in Note 2, as a troubled debt restructuring pursuant to the guidance under Accounting Standard Codification 470-60, Troubled Debt Restructuring |
Debt Issuance Costs | Debt Issuance Costs Debt issuance costs associated with our Credit Agreement are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with our Credit Agreement is reported within Other Assets Long-term debt, less current portion – carrying value |
Premiums Received and Discounts Provided on Debt Issuance | Premiums Received and Discounts Provided on Debt Issuance Premiums and discounts were recorded in Long-term debt, less current portion – carrying value |
Gain on Debt Transactions | Gain on Debt Transactions During 2018, the refinancing of our capital structure resulted in a gain of $47.1 million as a result of writing off the carrying value adjustments related to the debt issued in 2016, partially offset by premiums paid to repurchase and retire, repay or redeem all of our prior debt instruments. The gains recorded in 2017 and 2016 of $7.8 million and $123.9 million, respectively, relate to the debt exchange transaction occurring during 2016. Differences in the utilization of the payment-in-kind option during 2017 resulted in adjustments to the gain previously recorded in 2016. See Note 2 for additional information. |
Other Liabilities (Long-term) | Other Liabilities (long-term) The major categories recorded in Other liabilities December 31, 2018 2017 Apache lawsuit $ 49,500 $ 49,500 Uncertain tax positions including interest/penalties 11,523 11,015 Dispute related to royalty deductions 4,787 — Dispute related to royalty-in-kind 2,135 914 Other 745 5,437 Total other liabilities (long-term) $ 68,690 $ 66,866 |
Share-Based Compensation | Share-Based Compensation Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the closing price of the Company’s common stock at the date of grant. We recognize share-based compensation expense on a straight line basis over the period during which the recipient is required to provide service in exchange for the award. Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that are estimated to vest and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 for additional information. |
Other (Income) Expense, Net | Other (Income) Expense, Net For 2018, the amount consists of credits related to the de-recognition of certain liabilities that had exceeded the statute of limitations partially offset by expense related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program (as defined in Note 4). For 2017, the amount consists primarily of expense items related to the Apache lawsuit of $6.3 million, partially offset by loss-of-use reimbursements from a third-party for damages incurred at one of our platforms of $1.1 million. For 2016, the amount consists primarily of write-offs of debt issuance costs. |
Earnings (Loss) Per Share | Earnings (Loss) Per Share Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings (loss) per share under the two-class method when the effect is dilutive. See Note 14 for additional information. |
Recent Accounting Developments | Recent Accounting Developments In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases Topic 842 In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses Topic 326 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) – Targeted Improvements to Accounting for Hedging Activities |
Significant Accounting Polici_3
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Percentage of Revenue by Major Customers | The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude oil, NGLs and natural gas: Year Ended December 31, 2018 2017 2016 Customer Shell Trading (US) Co. 30 % 46 % 43 % BP Products North America 20 % ** ** Vitol Inc. 14 % 15 % 20 % ** Less than 10% |
Schedule of Changes to Allowance for Doubtful Accounts | The following table describes the balance and changes to the allowance for doubtful accounts: 2018 2017 2016 Allowance for doubtful accounts, beginning of period $ 9,114 $ 7,602 $ 2,490 Additional provisions for the year 1,233 1,512 5,112 Uncollectable accounts written off (655 ) — — Allowance for doubtful accounts, end of period $ 9,692 $ 9,114 $ 7,602 |
Schedule of Amounts Recorded in Prepaid Expenses and Other Assets | Amounts recorded in Prepaid expenses and other assets Year Ended December 31, 2018 2017 Derivatives – current (1) $ 60,687 $ — Prepaid/accrued insurance 2,987 2,401 Surety bonds unamortized premiums 2,210 2,676 Prepaid deposits related to royalties 8,872 6,456 Advances for capital expenditures 745 — Other 905 1,886 Prepaid expenses and other assets $ 76,406 $ 13,419 (1) Includes both open and closed contracts. |
Schedule of Oil and Natural Gas Properties and Other, Net at Cost | Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts excluded from amortization as of the dates presented in the following table (in thousands): December 31, 2018 2017 Oil and natural gas properties and equipment $ 8,169,871 $ 8,102,044 Furniture, fixtures and other 20,228 21,831 Total property and equipment 8,190,099 8,123,875 Less accumulated depreciation, depletion and amortization 7,674,678 7,544,859 Oil and natural gas properties and other, net $ 515,421 $ 579,016 |
Schedule of Other Assets (Long-term) | The major categories recorded in Other assets December 31, 2018 2017 Escrow deposit – Apache lawsuit $ 49,500 $ 49,500 Appeal bond deposits 6,925 6,925 Unamortized debt issuance costs 4,773 330 Investment in White Cap, LLC 2,586 2,511 Derivatives 21,275 — Unamortized brokerage fee for Monza 2,277 — Proportional consolidation of Monza's other assets (Note 4) 3,275 — Other 936 1,127 Total other assets $ 91,547 $ 60,393 |
Schedule of Accrued Liabilities | The major categories recorded in Accrued liabilities December 31, 2018 2017 Accrued interest $ 12,385 $ 4,200 Accrued salaries/payroll taxes/benefits 2,320 2,454 Incentive compensation plans 10,817 7,366 Litigation accruals 3,673 3,480 Other 416 430 Total accrued liabilities $ 29,611 $ 17,930 |
Schedule of Other Liabilities (Long-term) | The major categories recorded in Other liabilities December 31, 2018 2017 Apache lawsuit $ 49,500 $ 49,500 Uncertain tax positions including interest/penalties 11,523 11,015 Dispute related to royalty deductions 4,787 — Dispute related to royalty-in-kind 2,135 914 Other 745 5,437 Total other liabilities (long-term) $ 68,690 $ 66,866 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | The components of our long-term debt are presented in the following tables (in thousands): December 31, 2018 December 31, 2017 Adjustments to Adjustments to Carrying Carrying Carrying Carrying Principal Value (1) Value Principal Value (2) Value Credit Facility, due October 2022 $ 21,000 $ — $ 21,000 $ — $ — $ — 9.75 % Senior Second Lien Notes, due November 2023: 625,000 (12,465 ) 612,535 — — — 11.00% 1.5 Lien Term Loan, due November 2019: — — — 75,000 15,596 90,596 9.00 % Second Lien Term Loan, due May 2020: — — — 300,000 (4,381 ) 295,619 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020: — — — 171,769 40,617 212,386 8.50%/10.00% Third Lien PIK Toggle Notes, due June 2021: — — — 153,192 50,005 203,197 8.50% Unsecured Senior Notes, due June 2019 — — — 189,829 425 190,254 Total long-term debt 646,000 (12,465 ) 633,535 889,790 102,262 992,052 Current maturities of long-term debt (3) — — — — 22,925 22,925 Long term debt, less current maturities $ 646,000 $ (12,465 ) $ 633,535 $ 889,790 $ 79,337 $ 969,127 (1) Unamortized debt issuance costs. (2) Unamortized debt issuance costs, unamortized debt premiums, unamortized debt discounts, future interest payments for certain debt instruments and future payments-in-kind (“PIK”) for certain debt instruments recorded on an undiscounted basis. (3) Future interest payments due within twelve months on the 1.5 Lien Term Loan, Second Lien PIK Toggle Notes and Third Lien PIK Toggle Notes (these debt instruments are defined below). |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value of Derivatives and Long-Term Debt | The following table presents the fair value of our derivatives and long-term debt (in thousands): December 31, Hierarchy 2018 2017 Assets: Derivatives – open contracts Level 2 $ 74,580 $ — Liabilities: 9.75% Senior Second Lien Notes, due November 2023 Level 2 $ 546,875 $ — 11.00% 1.5 Lien Term Loan, due November 2019 Level 2 — 75,000 9.00 % Second Lien Term Loan, due May 2020 Level 2 — 288,000 9.00%/10.75% Second Lien PIK Toggle Notes, due May 2020 Level 2 — 162,322 8.50%/10.00% Third Lien PIK Toggle Notes due June 2021 Level 2 — 119,490 8.50% Unsecured Senior Notes, due June 2019 Level 2 — 178,439 Credit Agreement Level 2 21,000 — |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Reconciliation of Asset Retirement Obligations Liability | The following table is a reconciliation of our ARO liability (in thousands): Year Ended December 31, 2018 2017 Asset retirement obligations, beginning of period $ 300,446 $ 334,438 Liabilities settled (28,617 ) (72,409 ) Accretion of discount 18,431 17,172 Liabilities incurred and assumed through acquisition 4,286 163 Revisions of estimated liabilities (1) (2) 15,591 21,082 Asset retirement obligations, end of period 310,137 300,446 Less current portion 24,994 23,613 Long-term $ 285,143 $ 276,833 (1) Revisions in 2018 reflect cost estimate increases as a result of new data on the required scope of work becoming available to us through 2018. This new data included data realized during the planning phase of the projects, and as the projects proceeded through the execution phase. This new data indicated that the scope was larger and more difficult than the scope used for end of 2017 estimates. As an example, larger heavy lift vessels would be needed for certain platform removals, and certain wells needed additional well plugging operations to complete the decommissioning per agency requirements. (2) Revisions in 2017 were primarily related to increased costs associated with wells at four fields that experienced sustained casing pressure issues. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations. |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Open Commodity Derivative Contracts | The open contracts as of December 31, 2018 are presented in the following tables: Crude Oil: Swap, Priced off WTI (NYMEX) Termination Period Notional (1) Quantity (Bbls/day) Notional (1) Quantity (Bbls) Strike Price May 2020 1,500 775,500 $ 60.80 May 2020 5,000 2,585,000 61.00 May 2020 3,500 1,809,500 60.85 (1) Bbls = Barrels Crude Oil: Calls - Bought, Priced off WTI (NYMEX) Termination Period Notional (1) Quantity (Bbls/day) Notional (1) Quantity (Bbls) Strike Price May 2020 10,000 5,170,000 $ 61.00 (1) Bbls = Barrels Natural Gas: Two-way collars, Priced off Henry Hub (NYMEX) Termination Period Notional (2) Quantity (MMBtu/day) Notional (2) Quantity (MMBtu) Put Option Strike Price (Bought) Call Option Strike Price (Sold) June 2019 50,000 7,500,000 $ 2.49 $ 3.975 (2) MMBtu = Million British Thermal Units |
Summary of Open Contracts and Closed Contracts (Not Yet Settled) Commodity Derivative Contracts | The following amounts were recorded in the Consolidated Balance Sheets in the categories presented and include the fair value of open contracts and closed contracts, which had not yet settled (in thousands): December 31, 2018 2017 Prepaid and other assets – current $ 60,687 $ — Other assets – non-current 21,275 — |
Changes in Fair Value and Settlements of Commodity Derivative Contracts | Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands): Year Ended December 31, 2018 2017 2016 Derivative (gain) loss $ (53,798 ) $ (4,199 ) $ 2,926 |
Cash Receipts (Payments) on Derivative Settlements Included Within Net Cash Provided By Operating Activities | Cash (payments) receipts, net, on commodity derivative contract settlements, which include derivative premium payments, are included within Net cash provided by operating activities Year Ended December 31, 2018 2017 2016 Derivative cash (payments) receipts, net $ (28,164 ) $ 4,199 $ 4,746 |
Share-Based Awards and Cash-B_2
Share-Based Awards and Cash-Based Awards (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Summary of Share Activity Related to Restricted Stock Units | A summary of activity related to RSUs is as follows: 2018 2017 2016 Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Restricted Stock Units Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 5,765,251 $ 2.48 6,107,248 $ 2.73 3,474,079 $ 7.42 Granted 988,955 6.90 2,128,879 2.76 4,213,964 2.21 Vested (2,261,665 ) 2.21 (2,108,553 ) 3.45 (968,652 ) 16.69 Forfeited (1,136,624 ) 2.68 (362,323 ) 2.87 (612,143 ) 3.64 Nonvested, end of period 3,355,917 $ 3.90 5,765,251 $ 2.48 6,107,248 $ 2.73 |
Schedule of Restricted Stock Units Outstanding | Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2018 are eligible to vest in the year indicated in the table below: Restricted Stock Units 2019 2,429,006 2020 926,911 Total 3,355,917 |
Schedule of Restricted Stock Activity | A summary of activity related to Restricted Shares is as follows: 2018 2017 2016 Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Restricted Shares Weighted Average Grant Date Fair Value Per Share Nonvested, beginning of period 246,528 $ 2.27 161,296 $ 3.47 78,230 $ 8.95 Granted 41,544 6.74 147,372 1.90 126,128 2.22 Vested (106,240 ) 2.64 (62,140 ) 4.51 (43,062 ) 9.75 Nonvested, end of period 181,832 $ 3.08 246,528 $ 2.27 161,296 $ 3.47 |
Schedule of Restricted Stock Awards Outstanding | Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2018 are expected to vest as follows: Restricted Shares 2019 105,012 2020 62,972 2021 13,848 Total 181,832 |
Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit | A summary of compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands): Year Ended December 31, 2018 2017 2016 Share-based compensation expense from: Restricted stock units $ 3,260 $ 7,785 $ 10,640 Restricted stock 280 280 373 Total $ 3,540 $ 8,065 $ 11,013 Share-based compensation tax benefit: Tax benefit computed at the statutory rate $ 743 $ 1,694 $ 3,855 |
Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards | A summary of compensation expense related to share-based awards and cash-based awards is as follows (in thousands): Year Ended December 31, 2018 2017 2016 Share-based compensation included in: General and administrative $ 3,540 $ 8,065 $ 11,013 Cash-based incentive compensation included in: Lease operating expense 3,596 2,101 — General and administrative 9,586 5,032 — Total charged to operating income $ 16,722 $ 15,198 $ 11,013 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Expense (Benefit) | Components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2018 2017 2016 Current $ 35 $ (12,786 ) $ (71,768 ) Deferred 500 217 28,392 Total income tax expense (benefit) $ 535 $ (12,569 ) $ (43,376 ) |
Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) | The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense (benefit) is as follows (in thousands, except percentages): Year Ended December 31, 2018 2017 2016 Income tax expense (benefit) at the federal statutory rate $ 52,366 21.0 % $ 23,490 35.0 % $ (102,339 ) 35.0 % Compensation adjustments 457 0.2 664 1.0 4,920 (1.7 ) State income taxes 560 0.2 63 0.1 (755 ) 0.2 Debt restructuring cost — — 18 — 1,463 (0.5 ) Impact of U.S. tax reform 487 0.2 105,933 157.8 — — Gain on exchange of debt — — (24,981 ) (37.2 ) — — Valuation allowance (53,980 ) (21.7 ) (118,643 ) (176.8 ) 52,915 (18.1 ) Other 645 0.3 887 1.4 420 (0.1 ) Total income tax expense (benefit) $ 535 0.2 % $ (12,569 ) (18.7 %) $ (43,376 ) 14.8 % |
Significant Components of Deferred Tax Assets and Liabilities | Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities were as follows (in thousands): December 31, 2018 2017 Deferred tax liabilities: Derivatives $ 11,139 $ — Investment in non-consolidated entity 6,875 — Other 812 695 Total deferred tax liabilities 18,826 695 Deferred tax assets: Property and equipment 3,934 18,234 Asset retirement obligations 65,811 63,755 Federal net operating losses 10,039 18,988 State net operating losses 7,133 7,126 Interest expense carryover 41,814 — Exchange transaction — 55,807 Share-based compensation 583 1,335 Valuation allowance (117,764 ) (171,547 ) Other 7,091 6,805 Total deferred tax assets 18,641 503 Net deferred tax liabilities $ (185 ) $ (192 ) |
Net Operating Loss, Interest and Tax Credit Carryovers | The table below presents the details of our net operating loss and tax credit carryovers as of December 31, 2018 (in thousands): Amount Expiration Year Federal net operating loss $ 47,804 N/A State net operating losses 117,835 2025-2036 Interest limitation carryover 197,049 N/A |
Balances in Uncertain Tax Positions | Balances in the uncertain tax positions are as follows (in thousands): December 31, 2018 2017 Balance, beginning and end of period $ 9,482 $ 9,482 |
Earnings_ (Loss) Per Share (Tab
Earnings/ (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share | The following table presents the calculation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts): Year Ended December 31, 2018 2017 2016 Net income (loss) $ 248,827 $ 79,682 $ (249,020 ) Less portion allocated to nonvested shares 9,727 3,244 — Net income (loss) allocated to common shares $ 239,100 $ 76,438 $ (249,020 ) Weighted average common shares outstanding 139,002 137,617 95,644 Basic and diluted earnings (loss) per common share $ 1.72 $ 0.56 $ (2.60 ) Shares excluded due to being anti-dilutive (weighted-average) — — 5,269 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | The following table reflects our supplemental cash flow information (in thousands): Year Ended December 31, 2018 2017 2016 Supplemental cash items: Cash paid for interest, net of interest capitalized of $0 in 2018, $0 in 2017 and $520 in 2016 (1) $ 61,501 $ 65,873 $ 96,501 Cash paid for income taxes 138 185 310 Cash refunds received for income taxes 11,126 11,906 7,796 Cash paid for share-based compensation (2) 1,130 874 — Cash received for interest income 2,385 315 7,889 Non-cash investing activities: Accruals of property and equipment 18,575 33,003 9,129 ARO - additions, dispositions and revisions, net 19,877 21,245 10,865 Non-cash financing activities: Exchange transaction – non-cash securities issued: 11.00% 1.5 Lien Term Loan - interest payable — — 23,823 9.00%/10.75% Second Lien PIK Toggle Notes – carrying value — — 223,905 8.50%/10.00% Third Lien PIK Toggle Notes – carrying value — — 213,446 Common stock issued - fair value at issuance date — — 106,366 Exchange transaction – non-cash securities exchanged: 8.50% Unsecured Senior Notes – carrying value — — (712,967 ) (1) During 2018, 2017 and 2016, cash paid for interest included amounts related to the debt issued during 2016, which were accounted for under ASC 470-60 and recorded against the carrying value of the debt instruments on the Consolidated Balance Sheets and included in financing activities (2) During 2018 and 2017, cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016, only common shares were used to settle vested RSUs and Restrict stock. |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data | Unaudited quarterly financial data are as follows (in thousands, except per share amounts): 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended December 31, 2018 Revenues $ 134,213 $ 149,612 $ 153,459 $ 143,422 Operating income 38,739 48,467 57,147 102,674 Net income (1) 27,640 36,083 46,260 138,844 Basic and diluted earnings per common share 0.19 0.25 0.32 0.96 Year Ended December 31, 2017 Revenues $ 124,393 $ 123,323 $ 110,281 $ 129,099 Operating income 28,196 32,888 15,700 33,166 Net income (loss) (1) 24,299 33,315 (1,297 ) 23,365 Basic and diluted earnings (loss) per common share 0.17 0.23 (0.01 ) 0.16 (1) During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. During the first quarter of 2017, we recorded a gain on debt transactions of $7.8 million. See Note 2 and Note 9 for additional information. (2) The sum of the individual quarterly earnings (loss) per common share may not agree with the yearly amount due to each quarterly calculation is based on income for that quarter and the weighted average common shares outstanding for that quarter. |
Supplemental Oil and Gas Disc_2
Supplemental Oil and Gas Disclosures-unaudited (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Extractive Industries [Abstract] | |
Capitalized Costs Related to Oil and Natural Gas | Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions): December 31, 2018 2017 2016 Net capitalized cost: Proved oil and natural gas properties and equipment $ 8,169.9 $ 8,102.0 $ 7,932.5 Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities (7,665.1 ) (7,525.0 ) (7,387.8 ) Net capitalized costs related to producing activities $ 504.8 $ 577.0 $ 544.7 |
Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities | The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions): Year Ended December 31, 2018 2017 2016 Costs incurred: (1) Proved properties acquisitions $ 24.1 $ 1.1 $ 1.3 Exploration (2) (3) 49.9 62.0 4.8 Development 56.2 92.5 56.9 Unproved properties acquisitions — — 0.5 Total costs incurred in oil and gas property acquisition, exploration and development activities $ 130.2 $ 155.6 $ 63.5 (1) Includes net additions from capitalized ARO of $20.3 million, $21.3 million and $10.8 million during 2018, 2017 and 2016, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. (2) Includes seismic costs of $1.5 million, $0.5 million and $0.2 million incurred during 2018, 2017 and 2016, respectively. (3) Includes geological and geophysical costs charged to expense of $5.4 million, $4.2 million and $4.1 million during 2018, 2017 and 2016, respectively. |
Schedule of Depreciation, Depletion, Amortization and Accretion Expense | The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent (“Boe”) of products sold: Year Ended December 31, 2018 2017 2016 Depreciation, depletion, amortization and accretion per Boe $ 11.24 $ 10.68 $ 13.77 |
Schedule of Oil and Natural Gas Information | The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs and natural gas reserves. All of the reserves are located in the Unites States with all located in state and federal waters in the Gulf of Mexico. The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of such information. In addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. The prices used do not purport, nor should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual future prices and costs may differ materially from those used in determining our proved reserves for the periods presented. The prices used are presented in the section below entitled “ Standardized Measure of Discounted Future Net Cash Flows”. Total Energy Equivalent Reserves (1) Oil (MMBbls) NGLs (MMBbls) Natural Gas (Bcf) Oil Equivalent (MMBoe) Natural Gas Equivalent (Bcfe) Proved reserves as of Dec. 31, 2015 35.5 6.6 205.4 76.4 458.1 Revisions of previous estimates (2) 4.6 3.1 32.1 13.0 78.1 Production (7.2 ) (1.5 ) (39.7 ) (15.4 ) (92.2 ) Proved reserves as of Dec. 31, 2016 32.9 8.2 197.8 74.0 444.0 Revisions of previous estimates (3) 4.5 0.7 25.8 9.6 57.4 Extensions and discoveries (4) 4.1 0.3 5.4 5.2 31.3 Production (7.1 ) (1.4 ) (36.8 ) (14.6 ) (87.4 ) Proved reserves as of Dec. 31, 2017 34.4 7.8 192.2 74.2 445.3 Revisions of previous estimates (5) 11.6 2.8 40.4 21.1 126.7 Extensions and discoveries (6) 0.5 0.3 7.7 2.1 12.6 Purchase of minerals in place (7) 1.5 0.4 9.4 3.4 20.7 Sales of minerals in place (8) (2.2 ) (0.2 ) (7.2 ) (3.5 ) (21.2 ) Production (6.7 ) (1.3 ) (32.0 ) (13.3 ) (80.0 ) Proved reserves as of Dec. 31, 2018 39.1 9.8 210.5 84.0 504.1 Year-end proved developed reserves: 2018 31.5 7.8 166.8 67.0 402.2 2017 26.1 7.2 173.5 62.2 373.3 2016 26.6 7.6 183.1 64.7 388.2 Year-end proved undeveloped reserves: 2018 (9) 7.6 2.0 43.7 17.0 101.9 2017 8.3 0.6 18.7 12.0 72.0 2016 6.3 0.6 14.7 9.3 55.8 Volume measurements: MMBbls – million barrels for crude oil, condensate or NGLs Bcf – billion cubic feet MMBoe – million barrels of oil equivalent Bcfe – billion cubic feet of gas equivalent (1) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. (2) Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Virgo field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. (3) Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions. (4) Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. (5) Primarily related to upward revisions of 13.8 MMBoe at our Mahogany field and of 5.4 MMBoe at our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions. (6) Primarily related to extensions and discoveries of 1.3 MMBoe at our Virgo field and 0.7 MMBoe at our Ewing Bank 910 field. (7) Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg). (8) Primarily related to conveyance of interest in properties related to the JV Drilling Program. (9) We believe that we will be able to develop all but 1.8 MMBoe (approximately 11%) of the total of 17.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2018, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one in each field, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2021 and 2022, respectively. |
Schedule of Prices Weighted by Field Production Related to Proved Reserves | The following presents the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC guidance. The average commodity prices weighted by field production and after adjustments related to the proved reserves are as follows: December 31, 2018 2017 2016 2015 Oil - per barrel $ 65.21 $ 46.58 $ 36.28 $ 46.94 NGLs per barrel 29.73 22.65 16.82 17.60 Natural gas per Mcf 3.13 2.86 2.47 2.50 |
Standardized Measure of Discounted Future Net Cash Flow | The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore, among other things, future changes in prices and costs, revenues that could result from probable reserves which could become proved reserves in 2019 or later years and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2018 2017 2016 Standardized Measure of Discounted Future Net Cash Flows Future cash inflows $ 3,500.9 $ 2,328.8 $ 1,818.4 Future costs: Production (958.5 ) (813.8 ) (691.5 ) Development (272.4 ) (157.4 ) (141.1 ) Dismantlement and abandonment (355.9 ) (361.9 ) (427.7 ) Income taxes (1) (293.9 ) (74.8 ) — Future net cash inflows before 10% discount 1,620.2 920.9 558.1 10% annual discount factor (553.2 ) (180.3 ) (79.8 ) Total $ 1,067.0 $ 740.6 $ 478.3 (1) No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality. |
Schedule of Changes In Standardized Measure | The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions): Year Ended December 31, 2018 2017 2016 Changes in Standardized Measure Standardized measure, beginning of year $ 740.6 $ 478.3 $ 613.9 Increases (decreases): Sales and transfers of oil and gas produced, net of production costs (398.1 ) (315.3 ) (218.6 ) Net changes in price, net of future production costs 571.5 288.0 (275.2 ) Extensions and discoveries, net of future production and development costs 53.6 119.3 — Changes in estimated future development costs (114.7 ) (38.9 ) (32.5 ) Previously estimated development costs incurred 48.4 102.8 114.5 Revisions of quantity estimates 307.6 106.4 190.1 Accretion of discount 50.5 30.2 52.6 Net change in income taxes (133.4 ) (54.7 ) — Purchases of reserves in-place 27.8 — — Sales of reserves in-place (54.1 ) — — Changes in production rates due to timing and other (32.7 ) 24.5 33.5 Net increase (decrease) in standardized measure 326.4 262.3 (135.6 ) Standardized measure, end of year $ 1,067.0 $ 740.6 $ 478.3 |
Significant Accounting Polici_4
Significant Accounting Policies - Additional Information (Details) | Oct. 18, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)Platform | Dec. 31, 2016USD ($) | Oct. 18, 2018USD ($) | Oct. 17, 2018USD ($) |
Significant Accounting Policies [Line Items] | |||||||||
Natural gas imbalances | $ 4,100,000 | $ 4,100,000 | $ 4,100,000 | $ 4,700,000 | |||||
Oil and natural gas properties and equipment - full cost method, amount excluded from amortization | 0 | 0 | $ 0 | 0 | |||||
Percentage of discount from proved reserves | 10.00% | ||||||||
Ceiling test write-down of oil and natural gas properties | $ 0 | 0 | $ 279,063,000 | ||||||
Proved undeveloped reserves classification period to be drilled | 5 years | ||||||||
Gain on exchange of debt | $ 47,100,000 | $ 7,800,000 | $ 47,109,000 | $ 7,811,000 | 123,923,000 | ||||
Number of platforms damaged | Platform | 1 | ||||||||
Reimbursements from a third-party for damages | $ 1,100,000 | ||||||||
ASU 2016-02 | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Effect of adoption in asset and liabilities | $ 5,000,000 | ||||||||
Apache Corporation | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Expense related to lawsuit | $ 6,300,000 | ||||||||
Exchange Transaction | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Gain on exchange of debt | $ 123,900,000 | ||||||||
Fixtures and Non-Oil and Natural Gas Property and Equipment | Minimum | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Estimated useful lives | 5 years | ||||||||
Fixtures and Non-Oil and Natural Gas Property and Equipment | Maximum | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Estimated useful lives | 7 years | ||||||||
9.75% Senior Second Lien Notes, Due November 2023 | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Debt instrument maturity date | Nov. 1, 2023 | Nov. 1, 2023 | Nov. 1, 2023 | ||||||
Revolving Bank Credit Facility Due October 2022 | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Credit agreement expiration date | Oct. 18, 2022 | ||||||||
Credit Facility, Due October 2022 | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Debt instrument maturity date | Oct. 18, 2022 | ||||||||
Credit agreement expiration date | Oct. 18, 2022 | ||||||||
Credit facility borrowing base | $ 250,000,000 | $ 250,000,000 | $ 150,000,000 | ||||||
1.5 Lien Term Loan | Exchange Transaction | |||||||||
Significant Accounting Policies [Line Items] | |||||||||
Interest expense recorded for new debt | $ 0 |
Significant Accounting Polici_5
Significant Accounting Policies - Percentage of Revenue by Major Customers (Details) - Sales Revenue Net - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Shell Trading (US) Co. | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Percentage of receipts | 30.00% | 46.00% | 43.00% |
BP Products North America | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Percentage of receipts | 20.00% | ||
Vitol Inc. | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Percentage of receipts | 14.00% | 15.00% | 20.00% |
Significant Accounting Polici_6
Significant Accounting Policies - Schedule of Changes to Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Receivables [Abstract] | |||
Allowance for doubtful accounts, beginning of period | $ 9,114 | $ 7,602 | $ 2,490 |
Additional provisions for the year | 1,233 | 1,512 | 5,112 |
Uncollectable accounts written off | (655) | ||
Allowance for doubtful accounts, end of period | $ 9,692 | $ 9,114 | $ 7,602 |
Significant Accounting Polici_7
Significant Accounting Policies - Schedule of Amounts Recorded in Prepaid Expenses and Other Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Prepaid Expense And Other Assets Current [Abstract] | ||
Derivatives - current | $ 60,687 | |
Prepaid/accrued insurance | 2,987 | $ 2,401 |
Surety bonds unamortized premiums | 2,210 | 2,676 |
Prepaid deposits related to royalties | 8,872 | 6,456 |
Advances for capital expenditures | 745 | |
Other | 905 | 1,886 |
Prepaid expenses and other assets | $ 76,406 | $ 13,419 |
Significant Accounting Polici_8
Significant Accounting Policies - Schedule of Oil and Natural Gas Properties and Other, Net at Cost (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Property Plant And Equipment Net [Abstract] | ||
Oil and natural gas properties and equipment | $ 8,169,871 | $ 8,102,044 |
Furniture, fixtures and other | 20,228 | 21,831 |
Total property and equipment | 8,190,099 | 8,123,875 |
Less accumulated depreciation, depletion and amortization | 7,674,678 | 7,544,859 |
Oil and natural gas properties and other, net | $ 515,421 | $ 579,016 |
Significant Accounting Polici_9
Significant Accounting Policies - Schedule of Other Assets (Long-term) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Other Assets [Abstract] | ||
Escrow deposit – Apache lawsuit | $ 49,500 | $ 49,500 |
Appeal bond deposits | 6,925 | 6,925 |
Unamortized debt issuance costs | 4,773 | 330 |
Investment in White Cap, LLC | 2,586 | 2,511 |
Derivatives | 21,275 | |
Unamortized brokerage fee for Monza | 2,277 | |
Proportional consolidation of Monza's other assets (Note 4) | 3,275 | |
Other | 936 | 1,127 |
Total other assets | $ 91,547 | $ 60,393 |
Significant Accounting Polic_10
Significant Accounting Policies - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Payables And Accruals [Abstract] | ||
Accrued interest | $ 12,385 | $ 4,200 |
Accrued salaries/payroll taxes/benefits | 2,320 | 2,454 |
Incentive compensation plans | 10,817 | 7,366 |
Litigation accruals | 3,673 | 3,480 |
Other | 416 | 430 |
Total accrued liabilities | $ 29,611 | $ 17,930 |
Significant Accounting Polic_11
Significant Accounting Policies - Schedule of Other Liabilities (Long-term) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Other Liabilities Disclosure [Abstract] | ||
Apache lawsuit | $ 49,500 | $ 49,500 |
Uncertain tax positions including interest/penalties | 11,523 | 11,015 |
Dispute related to royalty deductions | 4,787 | |
Dispute related to royalty-in-kind | 2,135 | 914 |
Other | 745 | 5,437 |
Total other liabilities (long-term) | $ 68,690 | $ 66,866 |
Long-Term Debt - Components of
Long-Term Debt - Components of Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Oct. 18, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | |||
Principal | $ 646,000 | $ 889,790 | |
Principal, less current maturities | 646,000 | 889,790 | |
Adjustments to carrying value, Total | (12,465) | 102,262 | |
Adjustments to carrying value, Current maturities | 22,925 | ||
Adjustments to carrying value, less current maturities | (12,465) | 79,337 | |
Total long-term debt | 633,535 | 992,052 | |
Current maturities of long-term debt | 22,925 | ||
Long term debt, less current maturities | 633,535 | 969,127 | |
Credit Facility, Due October 2022 | |||
Debt Instrument [Line Items] | |||
Principal | 21,000 | ||
Carrying Value | 21,000 | ||
9.75% Senior Second Lien Notes, Due November 2023 | |||
Debt Instrument [Line Items] | |||
Principal | 625,000 | $ 625,000 | |
Adjustments to carrying value, Total | (12,465) | ||
Carrying Value | $ 612,535 | ||
11.00% 1.5 Lien Term Loan, Due November 2019 | |||
Debt Instrument [Line Items] | |||
Principal | 75,000 | ||
Adjustments to carrying value, Total | 15,596 | ||
Carrying Value | 90,596 | ||
9.00 % Second Lien Term Loan, Due May 2020 | |||
Debt Instrument [Line Items] | |||
Principal | 300,000 | ||
Adjustments to carrying value, Total | (4,381) | ||
Carrying Value | 295,619 | ||
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||
Debt Instrument [Line Items] | |||
Principal | 171,769 | ||
Adjustments to carrying value, Total | 40,617 | ||
Carrying Value | 212,386 | ||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||
Debt Instrument [Line Items] | |||
Principal | 153,192 | ||
Adjustments to carrying value, Total | 50,005 | ||
Carrying Value | 203,197 | ||
8.50% Unsecured Senior Notes, Due June 2019 | |||
Debt Instrument [Line Items] | |||
Principal | 189,829 | ||
Adjustments to carrying value, Total | 425 | ||
Carrying Value | $ 190,254 |
Long-Term Debt - Components o_2
Long-Term Debt - Components of Long-Term Debt (Parenthetical) (Details) | Oct. 18, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
Credit Facility, Due October 2022 | |||
Debt Instrument [Line Items] | |||
Debt instrument maturity date | Oct. 18, 2022 | ||
9.75% Senior Second Lien Notes, Due November 2023 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 9.75% | 9.75% | 9.75% |
Debt instrument maturity date | Nov. 1, 2023 | Nov. 1, 2023 | Nov. 1, 2023 |
11.00% 1.5 Lien Term Loan, Due November 2019 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 11.00% | 11.00% | |
Debt instrument maturity date | Nov. 15, 2019 | Nov. 15, 2019 | |
9.00 % Second Lien Term Loan, Due May 2020 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 9.00% | 9.00% | |
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 9.00% | 9.00% | |
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |
Debt instrument paid in kind interest rate | 10.75% | 10.75% | |
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% | |
Debt instrument maturity date | Jun. 15, 2021 | Jun. 15, 2021 | |
Debt instrument paid in kind interest rate | 10.00% | 10.00% | |
8.50% Unsecured Senior Notes, Due June 2019 | |||
Debt Instrument [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% | |
Debt instrument maturity date | Jun. 15, 2019 | Jun. 15, 2019 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions | Oct. 18, 2018 | Sep. 07, 2016 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Oct. 18, 2018 | Jun. 30, 2017 |
Debt Instrument [Line Items] | |||||||||||||
Aggregate annual maturities of long-term debt, 2019 | $ 0 | $ 0 | |||||||||||
Aggregate annual maturities of long-term debt, 2020 | 0 | 0 | |||||||||||
Aggregate annual maturities of long-term debt, 2021 | 0 | 0 | |||||||||||
Aggregate annual maturities of long-term debt, 2022 | 21,000,000 | 21,000,000 | |||||||||||
Aggregate annual maturities of long-term debt, 2023 | 625,000,000 | 625,000,000 | |||||||||||
Debt instrument aggregate principal amount | 646,000,000 | 646,000,000 | $ 889,790,000 | ||||||||||
Investment in Second Lien Term Loan | $ 5,000,000 | $ 5,000,000 | |||||||||||
Gain on exchange of debt | 47,100,000 | $ 7,800,000 | $ 47,109,000 | $ 7,811,000 | $ 123,923,000 | ||||||||
Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Gain on exchange of debt | 47,100,000 | ||||||||||||
Basic and diluted income (loss) per common share | $ 0.33 | ||||||||||||
Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Gain on exchange of debt | $ 123,900,000 | ||||||||||||
Basic and diluted income (loss) per common share | $ 0.06 | $ 1.30 | |||||||||||
Deal transaction costs | $ 18,900,000 | ||||||||||||
Common stock issued value per share | $ 1.76 | ||||||||||||
Additional expense charged to gain on debt transactions | $ 400,000 | ||||||||||||
Exchange Transaction | Common Stock | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt conversion, common stock shares issued | 60.4 | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 625,000,000 | $ 625,000,000 | $ 625,000,000 | $ 625,000,000 | |||||||||
Debt instrument interest rate | 9.75% | 9.75% | 9.75% | 9.75% | 9.75% | ||||||||
Debt instrument maturity date | Nov. 1, 2023 | Nov. 1, 2023 | Nov. 1, 2023 | ||||||||||
Debt instrument payment terms | Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year, beginning on May 1, 2019. | ||||||||||||
Annual effective interest rate | 10.30% | 10.30% | |||||||||||
Senior second lien notes repurchase price limit percentage | 101.00% | 101.00% | |||||||||||
Krohn entities purchase of Senior Second Lien Notes | $ 8,000,000 | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | Prior to November 1, 2020 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Redemption price percentage of principal amount plus accrued and unpaid interest | 100.00% | ||||||||||||
Redemption description | Prior to November 1, 2020, we may redeem all or any portion of the Senior Second Lien Notes at a redemption price equal to 100% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to November 1, 2020, we may, at our option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the Senior Second Lien Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 109.750% of the principal amount of the outstanding Senior Second Lien Notes plus accrued and unpaid interest, if any, to the redemption date. | ||||||||||||
Redemption price percentage of principal amount plus accrued and unpaid interest redeemable upon proceeds from equity offering | 109.75% | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | Prior to November 1, 2020 | Maximum | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Redemption price percentage | 35.00% | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | 12-month Period Beginning November 1, 2020 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Redemption price percentage of principal amount plus accrued and unpaid interest | 104.875% | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | 12-month Period Beginning November 1, 2021 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Redemption price percentage of principal amount plus accrued and unpaid interest | 102.438% | ||||||||||||
9.75% Senior Second Lien Notes, Due November 2023 | On November 1, 2022 and Thereafter | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Redemption price percentage of principal amount plus accrued and unpaid interest | 100.00% | ||||||||||||
Credit Facility, Due October 2022 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 21,000,000 | $ 21,000,000 | |||||||||||
Debt instrument maturity date | Oct. 18, 2022 | ||||||||||||
Credit agreement expiration date | Oct. 18, 2022 | ||||||||||||
Initial borrowing base and lending commitment | $ 250,000,000 | $ 250,000,000 | |||||||||||
Leverage ratio | 350.00% | ||||||||||||
Estimated derivative contracts projected date | Dec. 2, 2018 | ||||||||||||
Estimated derivative contracts projected production period | 18 months | ||||||||||||
Credit facility borrowings outstanding | $ 21,000,000 | $ 21,000,000 | $ 0 | ||||||||||
Letters of credit outstanding | $ 9,600,000 | $ 9,600,000 | 300,000 | ||||||||||
Credit Facility, Due October 2022 | Letters of Credit | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit facility maximum lender commitment | $ 30,000,000 | 30,000,000 | |||||||||||
Credit Facility, Due October 2022 | Scenario, Forecast | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Leverage ratio | 300.00% | 325.00% | 325.00% | 350.00% | |||||||||
Credit Facility, Due October 2022 | Two Quarters After Material Acquisition | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Leverage ratio | 350.00% | ||||||||||||
Credit Facility, Due October 2022 | Maximum | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Unused portion of the borrowing base commitment fee | 0.50% | ||||||||||||
Credit Facility, Due October 2022 | Maximum | Eurodollar | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument, basis spread on variable rate | 3.50% | ||||||||||||
Credit Facility, Due October 2022 | Maximum | Alternate Base Rate | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument, basis spread on variable rate | 2.50% | ||||||||||||
Credit Facility, Due October 2022 | Minimum | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit agreement, current ratio | 100.00% | ||||||||||||
Unused portion of the borrowing base commitment fee | 0.375% | ||||||||||||
Estimated percenatge of derivative contracts | 50.00% | ||||||||||||
Credit Facility, Due October 2022 | Minimum | Eurodollar | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument, basis spread on variable rate | 2.50% | ||||||||||||
Credit Facility, Due October 2022 | Minimum | Alternate Base Rate | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument, basis spread on variable rate | 1.50% | ||||||||||||
11.00% 1.5 Lien Term Loan, Due November 2019 | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 75,000,000 | $ 75,000,000 | |||||||||||
Debt instrument interest rate | 11.00% | 11.00% | |||||||||||
Debt instrument maturity date | Nov. 15, 2019 | ||||||||||||
Debt instrument, maturity date, description | “1.5 Lien Term Loan”) due November 15, 2019 | ||||||||||||
9.00% Term Loan, due May 15, 2020 | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 300,000,000 | $ 300,000,000 | |||||||||||
Debt instrument interest rate | 9.00% | 9.00% | |||||||||||
Debt instrument maturity date | May 15, 2020 | ||||||||||||
Debt instrument, maturity date, description | 9.00% Term Loan, due May 15, 2020 | ||||||||||||
9.00 % Second Lien Term Loan, Due May 2020 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 300,000,000 | ||||||||||||
Debt instrument interest rate | 9.00% | 9.00% | 9.00% | ||||||||||
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |||||||||||
9.00 % Second Lien Term Loan, Due May 2020 | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 177,500,000 | $ 177,500,000 | |||||||||||
Debt instrument maturity date | May 15, 2020 | ||||||||||||
Debt instrument, maturity date, description | 9.00%/10.75% Senior Second Lien PIK Toggle Notes (the “Second Lien PIK Toggle Notes”), due May 15, 2020 | ||||||||||||
9.00 % Second Lien Term Loan, Due May 2020 | Maximum | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument paid in kind interest rate | 10.75% | 10.75% | |||||||||||
9.00 % Second Lien Term Loan, Due May 2020 | Minimum | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument interest rate | 9.00% | 9.00% | |||||||||||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 153,192,000 | ||||||||||||
Debt instrument interest rate | 8.50% | 8.50% | 8.50% | ||||||||||
Debt instrument maturity date | Jun. 15, 2021 | Jun. 15, 2021 | |||||||||||
Debt instrument paid in kind interest rate | 10.00% | 10.00% | 10.00% | ||||||||||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 160,900,000 | $ 160,900,000 | |||||||||||
Debt instrument maturity date | Jun. 15, 2021 | ||||||||||||
Debt instrument, maturity date, description | 8.50%/10.00% Senior Third Lien PIK Toggle Notes (the “Third Lien PIK Toggle Notes”), due June 15, 2021 | ||||||||||||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 142,000,000 | ||||||||||||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Maximum | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument paid in kind interest rate | 10.00% | 10.00% | |||||||||||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | Minimum | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument interest rate | 8.50% | 8.50% | |||||||||||
8.50% Unsecured Senior Notes, Due June 2019 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 189,829,000 | ||||||||||||
Debt instrument interest rate | 8.50% | 8.50% | 8.50% | ||||||||||
Debt instrument maturity date | Jun. 15, 2019 | Jun. 15, 2019 | |||||||||||
8.50% Unsecured Senior Notes, Due June 2019 | Refinancing Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 189,800,000 | $ 189,800,000 | |||||||||||
Debt instrument interest rate | 8.50% | 8.50% | |||||||||||
Debt instrument maturity date | Jun. 15, 2019 | ||||||||||||
Debt instrument, maturity date, description | 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019 | ||||||||||||
8.50% Unsecured Senior Notes, Due June 2019 | Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 710,200,000 | ||||||||||||
Percentage of unsecured senior notes exchanged | 79.00% | ||||||||||||
8.50% Unsecured Senior Notes, Due June 2019 | Exchange Transaction | Common Stock | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt conversion, common stock shares issued | 60.4 | ||||||||||||
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 171,769,000 | ||||||||||||
Debt instrument interest rate | 9.00% | 9.00% | 9.00% | ||||||||||
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |||||||||||
Debt instrument paid in kind interest rate | 10.75% | 10.75% | 10.75% | ||||||||||
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 159,800,000 | ||||||||||||
11.00% 1.5 Lien Term Loan, Due November 2019 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 75,000,000 | ||||||||||||
Debt instrument interest rate | 11.00% | 11.00% | 11.00% | ||||||||||
Debt instrument maturity date | Nov. 15, 2019 | Nov. 15, 2019 | |||||||||||
11.00% 1.5 Lien Term Loan, Due November 2019 | Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt instrument aggregate principal amount | $ 75,000,000 | ||||||||||||
1.5 Lien Term Loan | Exchange Transaction | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Interest expense recorded for new debt | $ 0 | ||||||||||||
Second Lien PIK Toggle Notes and the Third Lien PIK Toggle Notes | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Net reduction to long term debt | $ 8,200,000 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Fair Value of Derivatives and Long-Term Debt (Details) - Fair Value, Inputs, Level 2 - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Liabilities: | ||
Credit Agreement | $ 21,000 | |
Open Contracts | ||
Assets: | ||
Derivatives | 74,580 | |
11.00% 1.5 Lien Term Loan, Due November 2019 | ||
Liabilities: | ||
Long-term debt, term loan fair value | $ 75,000 | |
9.00 % Second Lien Term Loan, Due May 2020 | ||
Liabilities: | ||
Long-term debt, term loan fair value | 288,000 | |
9.75% Senior Second Lien Notes, Due November 2023 | ||
Liabilities: | ||
Long-term debt, notes fair value | $ 546,875 | |
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | ||
Liabilities: | ||
Long-term debt, notes fair value | 162,322 | |
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | ||
Liabilities: | ||
Long-term debt, notes fair value | 119,490 | |
8.50% Unsecured Senior Notes, Due June 2019 | ||
Liabilities: | ||
Long-term debt, notes fair value | $ 178,439 |
Fair Value Measurements - Sch_2
Fair Value Measurements - Schedule of Fair Value of Derivatives and Long-Term Debt (Parenthetical) (Details) | Oct. 18, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
9.75% Senior Second Lien Notes, Due November 2023 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 9.75% | 9.75% | 9.75% |
Debt instrument maturity date | Nov. 1, 2023 | Nov. 1, 2023 | Nov. 1, 2023 |
11.00% 1.5 Lien Term Loan, Due November 2019 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 11.00% | 11.00% | |
Debt instrument maturity date | Nov. 15, 2019 | Nov. 15, 2019 | |
9.00 % Second Lien Term Loan, Due May 2020 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 9.00% | 9.00% | |
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 9.00% | 9.00% | |
Debt instrument maturity date | May 15, 2020 | May 15, 2020 | |
Debt instrument paid in kind interest rate | 10.75% | 10.75% | |
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% | |
Debt instrument maturity date | Jun. 15, 2021 | Jun. 15, 2021 | |
Debt instrument paid in kind interest rate | 10.00% | 10.00% | |
8.50% Unsecured Senior Notes, Due June 2019 | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% | |
Debt instrument maturity date | Jun. 15, 2019 | Jun. 15, 2019 |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Details) | Dec. 31, 2017DerivativeInstrument |
Fair Value Disclosures [Abstract] | |
Number of open derivative financial instruments | 0 |
Joint Venture Drilling Program
Joint Venture Drilling Program - Additional Information (Details) $ in Thousands | Mar. 12, 2018DrillingProjectUndevelopedDrillingProject | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Oil And Gas In Process Activities [Line Items] | ||||
Oil and natural gas properties | $ 515,421 | $ 579,016 | ||
Other assets | 91,547 | 60,393 | ||
Total revenues | 580,706 | 487,096 | $ 399,986 | |
Other expense | 3,871 | $ (5,127) | $ (1,369) | |
Monza Energy LLC | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Oil and natural gas properties | 8,800 | |||
Other assets | 3,300 | |||
Increase in working capital | 700 | |||
Total revenues | 4,300 | |||
Operating expense | 2,300 | |||
Other expense | 200 | |||
Maximum exposure amount by related party | 53,000 | |||
JV Drilling Program | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Percentage of revenue less expenses from joint venture | 20.00% | |||
Capital expenditures reimbursement, net | $ 20,000 | |||
JV Drilling Program | Mr. Tracy W. Krohn | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Minority interest ownership percentage by joint venture | 4.50% | |||
JV Drilling Program | Monza Energy LLC | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Joint venture maturity period | 3 years | |||
Joint venture ownership percentage contributed to related party | 88.94% | |||
Joint venture ownership percentage | 11.06% | |||
Number of undeveloped drilling project substituted | UndevelopedDrillingProject | 1 | |||
Undeveloped drilling project, joint venture ownership percentage contributed to related party | 58.71% | |||
Undeveloped drilling project, joint venture ownership percentage | 41.29% | |||
Commitment amount by investors | $ 361,400 | |||
Percentage of revenue less expenses from joint venture | 30.00% | |||
Percentage of estimated well cost | 20.00% | |||
Capital contribution payments from members of Monza | 114,700 | |||
JV Drilling Program | Monza Energy LLC | Mr. Tracy W. Krohn | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Capital commitment | $ 14,500 | |||
JV Drilling Program | Monza Energy LLC | Maximum | ||||
Oil And Gas In Process Activities [Line Items] | ||||
Number of drilling projects | DrillingProject | 14 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Millions | Sep. 28, 2018 | Apr. 05, 2018 |
Heidelberg Field Acquisition | ||
Business Acquisition [Line Items] | ||
Gross purchase price | $ 31.1 | |
Net purchase price | 16.8 | |
Letters of credit outstanding | 9.4 | |
Asset retirement obligations recognized | $ 3.6 | |
Purchase obligations due, year | 2,028 | |
Purchase commitment | $ 19.6 | |
Permian Basin | ||
Business Acquisition [Line Items] | ||
Net proceeds received from divestiture | $ 56.6 | |
Cobalt International Energy, Inc | Heidelberg Field Acquisition | ||
Business Acquisition [Line Items] | ||
Percentage of non-operated working interest acquired | 9.375% |
Asset Retirement Obligations -
Asset Retirement Obligations - Reconciliation of Asset Retirement Obligations Liability (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset retirement obligations, beginning of period | $ 300,446 | $ 334,438 | ||
Liabilities settled | (28,617) | (72,409) | $ (72,320) | |
Accretion of discount | 18,431 | 17,172 | 17,571 | |
Liabilities incurred and assumed through acquisition | 4,286 | 163 | ||
Revisions of estimated liabilities | [1],[2] | 15,591 | 21,082 | |
Asset retirement obligations, end of period | 310,137 | 300,446 | $ 334,438 | |
Less current portion | 24,994 | 23,613 | ||
Long-term | $ 285,143 | $ 276,833 | ||
[1] | Revisions in 2017 were primarily related to increased costs associated with wells at four fields that experienced sustained casing pressure issues. Wells that experience sustained casing pressure require more days and greater work scope to complete the abandonment project. Partially offsetting are downward revisions to cost estimates from service providers for plug and abandonment work at certain locations. | |||
[2] | Revisions in 2018 reflect cost estimate increases as a result of new data on the required scope of work becoming available to us through 2018. This new data included data realized during the planning phase of the projects, and as the projects proceeded through the execution phase. This new data indicated that the scope was larger and more difficult than the scope used for end of 2017 estimates. As an example, larger heavy lift vessels would be needed for certain platform removals, and certain wells needed additional well plugging operations to complete the decommissioning per agency requirements. |
Insurance Claims - Additional I
Insurance Claims - Additional Information (Details) - USD ($) | 3 Months Ended | 12 Months Ended | 126 Months Ended | |
Sep. 30, 2008 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2018 | |
Insurance [Abstract] | ||||
Retention amount per occurrence | $ 10,000,000 | |||
Maximum insurance coverage policy limit due to named windstorms for per incident | 150,000,000 | |||
Maximum insurance coverage policy limit except for property damage due to named windstorms | $ 250,000,000 | |||
Insurance reimbursements | $ 31,700,000 | $ 10,200,000 | ||
Cumulative insurance recoveries related to hurricanes | $ 203,100,000 | |||
Outstanding hurricane claims | $ 0 |
Derivative Financial Instrume_3
Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) | 12 Months Ended | |
Dec. 31, 2018MMBTU$ / Derivativebbl | ||
N Y M E X Crude Oil Swap | Open Crude Oil Derivative Contracts One | ||
Derivatives Fair Value [Line Items] | ||
Termination Period | May 2,020 | |
Notional Quantity (Bbls/day) | 1,500 | [1] |
Notional Quantity (Bbls) | 775,500 | [1] |
Strike Price | $ / Derivative | 60.80 | |
N Y M E X Crude Oil Swap | Open Crude Oil Derivative Contracts Two | ||
Derivatives Fair Value [Line Items] | ||
Termination Period | May 2,020 | |
Notional Quantity (Bbls/day) | 5,000 | [1] |
Notional Quantity (Bbls) | 2,585,000 | [1] |
Strike Price | $ / Derivative | 61 | |
N Y M E X Crude Oil Swap | Open Crude Oil Derivative Contracts Three | ||
Derivatives Fair Value [Line Items] | ||
Termination Period | May 2,020 | |
Notional Quantity (Bbls/day) | 3,500 | [1] |
Notional Quantity (Bbls) | 1,809,500 | [1] |
Strike Price | $ / Derivative | 60.85 | |
NYMEX Crude Oil Calls | Bought | ||
Derivatives Fair Value [Line Items] | ||
Termination Period | May 2,020 | |
Notional Quantity (Bbls/day) | 10,000 | [1] |
Notional Quantity (Bbls) | 5,170,000 | [1] |
Strike Price | $ / Derivative | 61 | |
NYMEX Natural Gas Two Way Collars | ||
Derivatives Fair Value [Line Items] | ||
Termination Period | June 2,019 | |
Notional Quantity (MMBtu/day) | MMBTU | 50,000 | [2] |
Notional Quantity (MMBtu) | MMBTU | 7,500,000 | [2] |
NYMEX Natural Gas Two Way Collars | Bought | Put Option | ||
Derivatives Fair Value [Line Items] | ||
Strike Price | $ / Derivative | 2.49 | |
NYMEX Natural Gas Two Way Collars | Sold | Call Option | ||
Derivatives Fair Value [Line Items] | ||
Strike Price | $ / Derivative | 3.975 | |
[1] | Bbls = Barrels | |
[2] | MMBtu = Million British Thermal Units |
Derivative Financial Instrume_4
Derivative Financial Instruments - Summary of Open Contracts and Closed Contracts (Not yet Settled) Commodity Derivative Contracts (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Derivatives Fair Value [Line Items] | |
Prepaid and other assets – current | $ 60,687 |
Other assets – non-current | 21,275 |
Open Contracts and Closed Contracts - Not Yet Settled | |
Derivatives Fair Value [Line Items] | |
Prepaid and other assets – current | 60,687 |
Other assets – non-current | $ 21,275 |
Derivative Financial Instrume_5
Derivative Financial Instruments - Changes in Fair Value and Settlements of Commodity Derivative Contracts (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Gain Loss On Derivative Instruments Net Pretax [Abstract] | ||||
Derivative (gain) loss | $ (59,700) | $ (53,798) | $ (4,199) | $ 2,926 |
Derivative Financial Instrume_6
Derivative Financial Instruments - Cash Receipts (Payments) on Derivative Settlements, Net Included within Net Cash Provided by Operating Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
Derivatives cash (payments) receipts, net | $ (28,164) | $ 4,199 | $ 4,746 |
Equity Transactions - Additiona
Equity Transactions - Additional Information (Details) - $ / shares | Sep. 07, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Equity Transactions [Line Items] | ||||
Common stock, shares authorized | 200,000,000 | 200,000,000 | ||
Common Stock, Regular | ||||
Equity Transactions [Line Items] | ||||
Paid cash dividends, per share | $ 0 | $ 0 | $ 0 | |
Minimum | ||||
Equity Transactions [Line Items] | ||||
Common stock, shares authorized | 118,300,000 | |||
Maximum | ||||
Equity Transactions [Line Items] | ||||
Common stock, shares authorized | 200,000,000 | |||
Exchange Transaction | Common Stock | ||||
Equity Transactions [Line Items] | ||||
Debt conversion, common stock shares issued | 60,400,000 |
Share-Based Awards and Cash-B_3
Share-Based Awards and Cash-Based Awards - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share based compensation performance awards grant performance period | 10 years | ||
Annual incentive awards payment period | 90 days | ||
Common stock available for award under plans | 11,852,592 | ||
Recognized incentive compensation expense | $ 3,540,000 | $ 8,065,000 | $ 11,013,000 |
Directors Compensation Plan | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Common stock available for award under plans | 128,980 | ||
Adjusted EBITDA and Adjusted EBITDA Margin | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Restricted stock units earning per share, minimum | 0.00% | 0.00% | 0.00% |
Restricted stock units earning per share, maximum | 100.00% | 100.00% | 100.00% |
Restricted Stock Units (RSUs) | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Common shares available for issuance reduced conversion basis | one-for-one basis | ||
Shares granted, grant date fair value | $ 6,800,000 | $ 5,900,000 | $ 9,300,000 |
Shares vested, vested date fair value | 11,000,000 | 5,500,000 | 2,400,000 |
Unrecognized share-based compensation expense | $ 6,400,000 | ||
Recognition period for unrecognized compensation expense | 2020-11 | ||
Recognized incentive compensation expense | $ 3,260,000 | 7,785,000 | 10,640,000 |
Restricted Shares | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Shares granted, grant date fair value | 300,000 | 300,000 | 300,000 |
Shares vested, vested date fair value | 700,000 | 100,000 | 100,000 |
Unrecognized share-based compensation expense | $ 400,000 | ||
Recognition period for unrecognized compensation expense | 2021-04 | ||
Recognized incentive compensation expense | $ 280,000 | $ 280,000 | $ 373,000 |
Restricted Shares | Directors Compensation Plan Share-Based Awards | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting rights description | Vesting occurs upon completion of the specified vesting period and one-third of each grant vests each year over a three-year period. | ||
Grant vesting period | 3 years | 3 years | 3 years |
2017 Cash-based Awards | Minimum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Adjusted EBITDA less interest expense | $ 200,000,000 | ||
2017 Annual Incentive Award Agreement | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Cash based award expected payment period | 2018-03 | ||
2018 Cash-based Awards | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Adjusted EBITDA less interest expense | $ 200,000,000 | ||
2018 Annual Incentive Award Agreement | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Cash based award expected payment period | 2019-03 | ||
2016 Cash-based Awards | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Recognized incentive compensation expense | $ 0 | $ 0 | $ 0 |
2016 Cash-based Awards | Minimum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Adjusted EBITDA less interest expense | $ 300,000,000 |
Share-Based Awards and Cash-B_4
Share-Based Awards and Cash-Based Awards - Summary of Share Activity Related to Restricted Stock Units (Details) - Restricted Stock Units (RSUs) - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Nonvested, beginning of period | 5,765,251 | 6,107,248 | 3,474,079 |
Granted | 988,955 | 2,128,879 | 4,213,964 |
Vested | (2,261,665) | (2,108,553) | (968,652) |
Forfeited | (1,136,624) | (362,323) | (612,143) |
Nonvested, end of period | 3,355,917 | 5,765,251 | 6,107,248 |
Weighted Average Grant Date Value, Beginning of period | $ 2.48 | $ 2.73 | $ 7.42 |
Weighted Average Grant Date Fair Value, Granted | 6.90 | 2.76 | 2.21 |
Weighted Average Grant Date Fair Value, Vested | 2.21 | 3.45 | 16.69 |
Weighted Average Grant Date Fair Value, Forfeited | 2.68 | 2.87 | 3.64 |
Weighted Average Grant Date Value, End of period | $ 3.90 | $ 2.48 | $ 2.73 |
Share-Based Awards and Cash-B_5
Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Units Outstanding (Details) - Restricted Stock Units (RSUs) - shares | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 3,355,917 | 5,765,251 | 6,107,248 | 3,474,079 |
2,019 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 2,429,006 | |||
2,020 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 926,911 |
Share-Based Awards and Cash-B_6
Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Activity (Details) - Restricted Shares - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Nonvested, beginning of period | 246,528 | 161,296 | 78,230 |
Granted | 41,544 | 147,372 | 126,128 |
Vested | (106,240) | (62,140) | (43,062) |
Nonvested, end of period | 181,832 | 246,528 | 161,296 |
Weighted Average Grant Date Value, Beginning of period | $ 2.27 | $ 3.47 | $ 8.95 |
Weighted Average Grant Date Fair Value, Granted | 6.74 | 1.90 | 2.22 |
Weighted Average Grant Date Fair Value, Vested | 2.64 | 4.51 | 9.75 |
Weighted Average Grant Date Value, End of period | $ 3.08 | $ 2.27 | $ 3.47 |
Share-Based Awards and Cash-B_7
Share-Based Awards and Cash-Based Awards - Schedule of Restricted Stock Awards Outstanding (Details) - Restricted Shares - shares | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 181,832 | 246,528 | 161,296 | 78,230 |
2,019 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 105,012 | |||
2,020 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 62,972 | |||
2,021 | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Awards expected to vest by period | 13,848 |
Share-Based Awards and Cash-B_8
Share-Based Awards and Cash-Based Awards - Summary of Compensation Expense under Share-Based Payment Arrangements and Related Tax Benefit (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | $ 3,540 | $ 8,065 | $ 11,013 |
Tax benefit computed at the statutory rate | 743 | 1,694 | 3,855 |
Restricted Stock Units (RSUs) | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | 3,260 | 7,785 | 10,640 |
Restricted Shares | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Share-based compensation | $ 280 | $ 280 | $ 373 |
Share-Based Awards and Cash-B_9
Share-Based Awards and Cash-Based Awards - Summary of Compensation Expense Related to Share-Based Awards and Cash-Based Awards (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Share-based compensation charged to operating income | $ 3,540 | $ 8,065 | $ 11,013 |
Total charged to operating income | 16,722 | 15,198 | 11,013 |
General And Administrative Expense | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Share-based compensation charged to operating income | 3,540 | 8,065 | $ 11,013 |
Cash-based incentive compensation charged to operating income | 9,586 | 5,032 | |
Lease Operating Expense | |||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||
Cash-based incentive compensation charged to operating income | $ 3,596 | $ 2,101 |
Employee Benefit Plan - Additio
Employee Benefit Plan - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Compensation And Retirement Disclosure [Abstract] | |||
Percentage of matching contribution of each participants | 100.00% | ||
Maximum contribution percentage of participating employees | 6.00% | ||
Year of service on which employer's matching contribution under 401K plan will be 100% vested | 5 years | ||
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage | 20.00% | ||
Company's contribution to 401K plan | $ 2 | $ 1.4 | $ 0.4 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||
Current | $ 35 | $ (12,786) | $ (71,768) |
Deferred | 500 | 217 | 28,392 |
Total income tax expense (benefit) | $ 535 | $ (12,569) | $ (43,376) |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Income Taxes Computed to Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Income tax expense (benefit) at the federal statutory rate | $ 52,366 | $ 23,490 | $ (102,339) |
Compensation adjustments | 457 | 664 | 4,920 |
State income taxes | 560 | 63 | (755) |
Debt restructuring cost | 18 | 1,463 | |
Impact of U.S. tax reform | 487 | 105,933 | |
Gain on exchange of debt | (24,981) | ||
Valuation allowance | (53,980) | (118,643) | 52,915 |
Other | 645 | 887 | 420 |
Total income tax expense (benefit) | $ 535 | $ (12,569) | $ (43,376) |
Income tax expense (benefit) at the federal statutory rate, tax rate | 21.00% | 35.00% | 35.00% |
Compensation adjustments, tax rate | 0.20% | 1.00% | (1.70%) |
State income taxes, tax rate | 0.20% | 0.10% | 0.20% |
Debt restructuring cost, tax rate | (0.50%) | ||
Impact of U.S. tax reform, tax rate | 0.20% | 157.80% | |
Gain on exchange of debt, tax rate | (37.20%) | ||
Valuation allowance, tax rate | (21.70%) | (176.80%) | (18.10%) |
Other, tax rate | 0.30% | 1.40% | (0.10%) |
Total income tax expense (benefit), tax rate | 0.20% | (18.70%) | 14.80% |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Federal statutory income tax rate | 21.00% | 35.00% | 35.00% | |
Cash paid for income taxes | $ 138 | $ 185 | $ 310 | |
Income tax refund received | 11,126 | 11,906 | 7,796 | |
Current income taxes receivable | $ 13,006 | 54,076 | 13,006 | |
Increase and (decrease) in valuation allowance | (105,900) | (53,800) | (118,600) | |
Income tax expense (benefit) adjustment | $ 500 | |||
Minimum | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Estimated recognized tax benefits | 11,500 | |||
Maximum | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Estimated recognized tax benefits | 12,000 | |||
Tax Year 2016, 2017 and 2018 | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Income tax refund received related to NOL claim | $ 11,100 | $ 11,900 | $ 7,800 | |
Earliest Tax Year | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Tax years under examination | 2,013 | |||
Latest Tax Year | ||||
Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||
Tax years under examination | 2,018 |
Income Taxes - Significant Comp
Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax liabilities: | ||
Derivatives | $ 11,139 | |
Investment in non-consolidated entity | 6,875 | |
Other | 812 | $ 695 |
Total deferred tax liabilities | 18,826 | 695 |
Deferred tax assets: | ||
Property and equipment | 3,934 | 18,234 |
Asset retirement obligations | 65,811 | 63,755 |
Federal net operating losses | 10,039 | 18,988 |
State net operating losses | 7,133 | 7,126 |
Interest expense carryover | 41,814 | |
Exchange transaction | 55,807 | |
Share-based compensation | 583 | 1,335 |
Valuation allowance | (117,764) | (171,547) |
Other | 7,091 | 6,805 |
Total deferred tax assets | 18,641 | 503 |
Net deferred tax liabilities | $ (185) | $ (192) |
Income Taxes - Net Operating Lo
Income Taxes - Net Operating Loss, Interest and Tax Credit Carryovers (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Operating Loss Carryforwards [Line Items] | |
Interest limitation carryover | $ 197,049 |
Internal Revenue Service (IRS) | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | 47,804 |
State and Local Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | $ 117,835 |
State and Local Jurisdiction | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | Dec. 31, 2025 |
State and Local Jurisdiction | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss, expiration year | Dec. 31, 2036 |
Income Taxes - Balances in Unce
Income Taxes - Balances in Uncertain Tax Positions (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Income Tax Disclosure [Abstract] | ||
Balance, beginning and end of period | $ 9,482 | $ 9,482 |
Earnings_ (Loss) Per Share - Sc
Earnings/ (Loss) Per Share - Schedule of Calculation of Basic and Diluted Earnings (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||||||
Earnings Per Share, Basic and Diluted [Abstract] | |||||||||||||||||||
Net income (loss) | $ 138,844 | [1] | $ 46,260 | [1] | $ 36,083 | [1] | $ 27,640 | [1] | $ 23,365 | [1] | $ (1,297) | [1] | $ 33,315 | [1] | $ 24,299 | [1] | $ 248,827 | $ 79,682 | $ (249,020) |
Less portion allocated to nonvested shares | 9,727 | 3,244 | |||||||||||||||||
Net income (loss) allocated to common shares | $ 239,100 | $ 76,438 | $ (249,020) | ||||||||||||||||
Weighted average common shares outstanding | 139,002 | 137,617 | 95,644 | ||||||||||||||||
Basic and diluted earnings (loss) per common share | $ 0.96 | $ 0.32 | $ 0.25 | $ 0.19 | $ 0.16 | $ (0.01) | $ 0.23 | $ 0.17 | $ 1.72 | $ 0.56 | $ (2.60) | ||||||||
Shares excluded due to being anti-dilutive (weighted-average) | 5,269 | ||||||||||||||||||
[1] | During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. During the first quarter of 2017, we recorded a gain on debt transactions of $7.8 million. See Note 2 and Note 9 for additional information. |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Supplemental cash items: | ||||
Cash paid for interest, net of interest capitalized of $0 in 2018, $0 in 2017 and $520 in 2016 | [1] | $ 61,501 | $ 65,873 | $ 96,501 |
Cash paid for income taxes | 138 | 185 | 310 | |
Cash refunds received for income taxes | 11,126 | 11,906 | 7,796 | |
Cash paid for share-based compensation | [2] | 1,130 | 874 | |
Cash received for interest income | 2,385 | 315 | 7,889 | |
Non-cash investing activities: | ||||
Accruals of property and equipment | 18,575 | 33,003 | 9,129 | |
ARO - additions, dispositions and revisions, net | $ 19,877 | $ 21,245 | 10,865 | |
Non-cash financing activities: | ||||
Common stock issued - fair value at issuance date | 106,366 | |||
11.00% 1.5 Lien Term Loan, Due November 2019 | ||||
Non-cash financing activities: | ||||
Exchange transaction — non-cash securities issued, value | 23,823 | |||
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | ||||
Non-cash financing activities: | ||||
Exchange transaction — non-cash securities issued, value | 223,905 | |||
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | ||||
Non-cash financing activities: | ||||
Exchange transaction — non-cash securities issued, value | 213,446 | |||
8.50% Unsecured Senior Notes, Due June 2019 | ||||
Non-cash financing activities: | ||||
Exchange transaction — non-cash securities exchanged, value | $ (712,967) | |||
[1] | During 2018, 2017 and 2016, cash paid for interest included amounts related to the debt issued during 2016, which were accounted for under ASC 470-60 and recorded against the carrying value of the debt instruments on the Consolidated Balance Sheets and included in financing activities on the Consolidated Statements of Cash Flows. | |||
[2] | During 2018 and 2017, cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were used to settle all other vested RSUs and to settle restricted stock. During 2016, only common shares were used to settle vested RSUs and Restrict stock. |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Line Items] | |||
Cash paid, interest capitalized | $ 0 | $ 0 | $ 520 |
11.00% 1.5 Lien Term Loan, Due November 2019 | |||
Supplemental Cash Flow Elements [Line Items] | |||
Debt instrument interest rate | 11.00% | 11.00% | |
9.00%/10.75% Second Lien PIK Toggle Notes, Due May 2020 | |||
Supplemental Cash Flow Elements [Line Items] | |||
Debt instrument interest rate | 9.00% | 9.00% | |
Debt instrument paid in kind interest rate | 10.75% | 10.75% | |
8.50%/10.00% Third Lien PIK Toggle Notes, Due June 2021 | |||
Supplemental Cash Flow Elements [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% | |
Debt instrument paid in kind interest rate | 10.00% | 10.00% | |
8.50% Unsecured Senior Notes, Due June 2019 | |||
Supplemental Cash Flow Elements [Line Items] | |||
Debt instrument interest rate | 8.50% | 8.50% |
Commitments - Additional Inform
Commitments - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments [Line Items] | |||
Minimum future lease payments due under noncancelable operating leases, 2019 | $ 1,500,000 | ||
Minimum future lease payments due under noncancelable operating leases, 2020 | 1,600,000 | ||
Minimum future lease payments due under noncancelable operating leases, 2021 | 1,600,000 | ||
Minimum future lease payments due under noncancelable operating leases, 2022 | 1,600,000 | ||
Minimum future lease payments due under noncancelable operating leases, thereafter | 0 | ||
Total rent expense | 3,400,000 | $ 3,000,000 | $ 3,200,000 |
Escrow related to Purchase and Sale Agreement | 49,500,000 | 49,500,000 | |
Collateral deposits | 6,900,000 | ||
Expenses related to surety bonds | 5,900,000 | $ 5,700,000 | $ 4,300,000 |
Drilling Rig Commitments | |||
Commitments [Line Items] | |||
Minimum future lease payments due under noncancelable operating leases, 2018 | 9,700,000 | ||
Heidelberg Field Acquisition | |||
Commitments [Line Items] | |||
Future estimated payment, 2019 | 4,900,000 | ||
Future estimated payment, 2020 | 4,000,000 | ||
Future estimated payment, 2021 | 2,300,000 | ||
Future estimated payment, 2022 | 1,700,000 | ||
Future estimated payment, 2023 | 1,200,000 | ||
Future estimated payment, thereafter | 2,000,000 | ||
Surety Bonds | |||
Commitments [Line Items] | |||
Future estimated payment, 2019 | 4,500,000 | ||
Future estimated payment, 2020 | 4,200,000 | ||
Future estimated payment, 2021 | 3,900,000 | ||
Future estimated payment, 2022 | 3,900,000 | ||
Future estimated payment, 2023 | 3,800,000 | ||
Future estimated payment, thereafter | 33,600,000 | ||
Surety Bonds | Other commitment | |||
Commitments [Line Items] | |||
Security requirement minimum | 64,000,000 | ||
Security requirement maximum | 94,000,000 | ||
Surety Bonds | Total E&P Member | |||
Commitments [Line Items] | |||
Security amount requirement | 88,500,000 | ||
Escrow related to Purchase and Sale Agreement | 0 | ||
Additional security requirements for 2019 | 91,000,000 | ||
Additional security requirements for 2023 | 103,000,000 | ||
Annual increment in threshold | $ 3,000,000 |
Related Parties - Additional In
Related Parties - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Principal | $ 646,000 | $ 889,790 | |
Airplane Services | |||
Related Party Transaction [Line Items] | |||
Related party transactions | 1,300 | 1,200 | $ 1,100 |
Marine Transportation and Logistic Services | |||
Related Party Transaction [Line Items] | |||
Related party transactions | 200 | 200 | |
Payments to related party transactions | 21,000 | $ 22,800 | 17,300 |
Marine Transportation and Logistic Services | Maximum | |||
Related Party Transaction [Line Items] | |||
Related party transactions | $ 200 | ||
CEO and Largest Shareholder | Senior Second Lien Note Issuance | |||
Related Party Transaction [Line Items] | |||
Principal | $ 8,000 |
Contingencies - Additional Info
Contingencies - Additional Information (Details) | 12 Months Ended | |||||||
Dec. 31, 2018USD ($)claim | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2017USD ($) | May 31, 2017USD ($) | Jan. 27, 2017USD ($) | Dec. 15, 2014DeepwaterWell | Dec. 31, 2010USD ($) | |
Loss Contingencies [Line Items] | ||||||||
Number of deepwater wells abandoned | DeepwaterWell | 3 | |||||||
Deposit Into registry of court | $ 49,500,000 | $ 49,500,000 | ||||||
Loss contingency accrued amount | 49,500,000 | 49,500,000 | ||||||
Notified disallowed amount in reductions taken by ONRR | $ 4,700,000 | $ 4,700,000 | ||||||
Bond requied to post in order to appeal | 7,200,000 | |||||||
Cash collateral required to appeal | $ 6,900,000 | |||||||
Liability reserve | $ 2,100,000 | |||||||
Royalty payment processing revised period | 84 months | |||||||
Royalties paid | $ 600,000 | 1,600,000 | $ 500,000 | |||||
Outstanding obligation to secure financial assurances upon rescindment | 0 | |||||||
BSEE | ||||||||
Loss Contingencies [Line Items] | ||||||||
Loss contingency accrued amount | $ 3,500,000 | |||||||
Number of notices | claim | 9 | |||||||
Proposed civil penalties related to various incidents of noncompliance, total | $ 7,700,000 | |||||||
Payments for civil penalty | $ 0 | 200,000 | $ 100,000 | |||||
Apache Corporation | Judicial Ruling | ||||||||
Loss Contingencies [Line Items] | ||||||||
Amount owed to Apache under judicial decision | $ 43,200,000 | |||||||
Prejudgment interest, attorney fees and judgment costs | $ 6,300,000 | |||||||
Apache Corporation | Judicial Ruling | Other Income/Expense | ||||||||
Loss Contingencies [Line Items] | ||||||||
Recognized prejudgment interest, attorney fees and judgment costs. | 6,300,000 | |||||||
Apache Corporation | Judicial Ruling | Asset Retirement Obligation | ||||||||
Loss Contingencies [Line Items] | ||||||||
Capitalized loss contingency damages payable to other party except attorney fees judgment costs and prejudgment interest | 43,200,000 | |||||||
Apache Corporation | Judicial Ruling | Other Noncurrent Assets | ||||||||
Loss Contingencies [Line Items] | ||||||||
Deposit Into registry of court | $ 49,500,000 | |||||||
Apache Corporation | Judicial Ruling | Other Noncurrent Liabilities | ||||||||
Loss Contingencies [Line Items] | ||||||||
Loss contingency accrued amount | $ 49,500,000 |
Selected Quarterly Financial _3
Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Revenues | $ 143,422 | $ 153,459 | $ 149,612 | $ 134,213 | $ 129,099 | $ 110,281 | $ 123,323 | $ 124,393 | |||||||||||
Operating income (loss) | 102,674 | 57,147 | 48,467 | 38,739 | 33,166 | 15,700 | 32,888 | 28,196 | $ 247,027 | $ 109,950 | $ (330,568) | ||||||||
Net income (loss) | $ 138,844 | [1] | $ 46,260 | [1] | $ 36,083 | [1] | $ 27,640 | [1] | $ 23,365 | [1] | $ (1,297) | [1] | $ 33,315 | [1] | $ 24,299 | [1] | $ 248,827 | $ 79,682 | $ (249,020) |
Basic and diluted earnings per common share | $ 0.96 | $ 0.32 | $ 0.25 | $ 0.19 | $ 0.16 | $ (0.01) | $ 0.23 | $ 0.17 | $ 1.72 | $ 0.56 | $ (2.60) | ||||||||
[1] | During the fourth quarter of 2018, we recorded a gain on debt transactions of $47.1 million and a derivative gain of $59.7 million. During the first quarter of 2017, we recorded a gain on debt transactions of $7.8 million. See Note 2 and Note 9 for additional information. |
Selected Quarterly Financial _4
Selected Quarterly Financial Data (Parenthetical) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||
Gain on debt transactions | $ 47,100 | $ 7,800 | $ 47,109 | $ 7,811 | $ 123,923 |
Derivative gain | $ 59,700 | $ 53,798 | $ 4,199 | $ (2,926) |
Supplemental Oil and Gas Disc_3
Supplemental Oil and Gas Disclosures - Capitalized Costs Related to Oil and Natural Gas (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Net capitalized cost: | |||
Proved oil and natural gas properties and equipment | $ 8,169.9 | $ 8,102 | $ 7,932.5 |
Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities | (7,665.1) | (7,525) | (7,387.8) |
Net capitalized costs related to producing activities | $ 504.8 | $ 577 | $ 544.7 |
Supplemental Oil and Gas Disc_4
Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Costs incurred: | ||||
Proved properties acquisitions | [1] | $ 24.1 | $ 1.1 | $ 1.3 |
Exploration | [1],[2],[3] | 49.9 | 62 | 4.8 |
Development | [1] | 56.2 | 92.5 | 56.9 |
Unproved property acquisitions | [1] | 0.5 | ||
Total costs incurred in oil and gas property acquisition, exploration and development activities | [1] | $ 130.2 | $ 155.6 | $ 63.5 |
[1] | Includes net additions from capitalized ARO of $20.3 million, $21.3 million and $10.8 million during 2018, 2017 and 2016, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred, divestitures and revisions of estimates. | |||
[2] | Includes geological and geophysical costs charged to expense of $5.4 million, $4.2 million and $4.1 million during 2018, 2017 and 2016, respectively. | |||
[3] | Includes seismic costs of $1.5 million, $0.5 million and $0.2 million incurred during 2018, 2017 and 2016, respectively. |
Supplemental Oil and Gas Disc_5
Supplemental Oil and Gas Disclosures - Cost Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Capitalized Costs Oil And Gas Producing Activities Net [Abstract] | |||
Additions of asset retirement obligations | $ 20.3 | $ 21.3 | $ 10.8 |
Seismic costs | 1.5 | 0.5 | 0.2 |
Geological and geophysical costs | $ 5.4 | $ 4.2 | $ 4.1 |
Supplemental Oil and Gas Disc_6
Supplemental Oil and Gas Disclosures - Schedule of Depreciation, Depletion, Amortization and Accretion Expense (Details) - $ / Boe | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Capitalized Costs Oil And Gas Producing Activities Net [Abstract] | |||
Depreciation, depletion, amortization and accretion per Boe | 11.24 | 10.68 | 13.77 |
Supplemental Oil and Gas Disc_7
Supplemental Oil and Gas Disclosures - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Capitalized Costs Oil And Gas Producing Activities Net [Abstract] | |
Percentage non-operated non-producing reserves | 13.00% |
Present value discounted percentage | 10.00% |
Supplemental Oil and Gas Disc_8
Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, NGLs and Natural Gas Reserves (Details) Bcfe in Millions | 12 Months Ended | ||||||
Dec. 31, 2018MMBoeBcfeMMBblsBcf | Dec. 31, 2017MMBoeBcfeMMBblsBcf | Dec. 31, 2016MMBoeBcfeMMBblsBcf | |||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 6.2 | 14.2 | |||||
Oil | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 34.4 | 32.9 | 35.5 | ||||
Revisions of previous estimates | 11.6 | [1] | 4.5 | [2] | 4.6 | [3] | |
Extensions and discoveries | 0.5 | [4] | 4.1 | [5] | |||
Purchase of minerals in place | [6] | 1.5 | |||||
Sales of minerals in place | [7] | (2.2) | |||||
Production | (6.7) | (7.1) | (7.2) | ||||
Proved reserves, ending balance | 39.1 | 34.4 | 32.9 | ||||
Oil | Proved Developed Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 26.1 | 26.6 | |||||
Proved reserves, ending balance | 31.5 | 26.1 | 26.6 | ||||
Oil | Proved Undeveloped Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 8.3 | 6.3 | |||||
Proved reserves, ending balance | 7.6 | [8] | 8.3 | 6.3 | |||
NGLs | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 7.8 | 8.2 | 6.6 | ||||
Revisions of previous estimates | 2.8 | [1] | 0.7 | [2] | 3.1 | [3] | |
Extensions and discoveries | 0.3 | [4] | 0.3 | [5] | |||
Purchase of minerals in place | [6] | 0.4 | |||||
Sales of minerals in place | [7] | (0.2) | |||||
Production | (1.3) | (1.4) | (1.5) | ||||
Proved reserves, ending balance | 9.8 | 7.8 | 8.2 | ||||
NGLs | Proved Developed Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 7.2 | 7.6 | |||||
Proved reserves, ending balance | 7.8 | 7.2 | 7.6 | ||||
NGLs | Proved Undeveloped Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | 0.6 | 0.6 | |||||
Proved reserves, ending balance | 2 | [8] | 0.6 | 0.6 | |||
Natural Gas | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcf | 192,200 | 197,800 | 205,400 | ||||
Revisions of previous estimates | Bcf | 40,400 | [1] | 25,800 | [2] | 32,100 | [3] | |
Extensions and discoveries | Bcf | 7,700 | [4] | 5,400 | [5] | |||
Purchase of minerals in place | Bcf | [6] | 9,400 | |||||
Sales of minerals in place | Bcf | [7] | (7,200) | |||||
Production | Bcf | (32,000) | (36,800) | (39,700) | ||||
Proved reserves, ending balance | Bcf | 210,500 | 192,200 | 197,800 | ||||
Natural Gas | Proved Developed Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcf | 173,500 | 183,100 | |||||
Proved reserves, ending balance | Bcf | 166,800 | 173,500 | 183,100 | ||||
Natural Gas | Proved Undeveloped Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcf | 18,700 | 14,700 | |||||
Proved reserves, ending balance | Bcf | 43,700 | [8] | 18,700 | 14,700 | |||
Barrel Equivalent | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | MMBoe | [9] | 74.2 | 74 | 76.4 | |||
Revisions of previous estimates | MMBoe | [9] | 21.1 | [1] | 9.6 | [2] | 13 | [3] |
Extensions and discoveries | MMBoe | [9] | 2.1 | [4] | 5.2 | [5] | ||
Purchase of minerals in place | MMBoe | [6],[9] | 3.4 | |||||
Sales of minerals in place | MMBoe | [7],[9] | (3.5) | |||||
Production | MMBoe | [9] | (13.3) | (14.6) | (15.4) | |||
Proved reserves, ending balance | MMBoe | [9] | 84 | 74.2 | 74 | |||
Barrel Equivalent | Proved Developed Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | MMBoe | [9] | 62.2 | 64.7 | ||||
Proved reserves, ending balance | MMBoe | [9] | 67 | 62.2 | 64.7 | |||
Barrel Equivalent | Proved Undeveloped Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | MMBoe | [9] | 12 | 9.3 | ||||
Proved reserves, ending balance | MMBoe | [9] | 17 | [8] | 12 | 9.3 | ||
Natural Gas Equivalent | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcfe | [9] | 445.3 | 444 | 458.1 | |||
Revisions of previous estimates | Bcfe | [9] | 126.7 | [1] | 57.4 | [2] | 78.1 | [3] |
Extensions and discoveries | Bcfe | [9] | 12.6 | [4] | 31.3 | [5] | ||
Purchase of minerals in place | Bcfe | [6],[9] | 20.7 | |||||
Sales of minerals in place | Bcfe | [7],[9] | (21.2) | |||||
Production | Bcfe | [9] | (80) | (87.4) | (92.2) | |||
Proved reserves, ending balance | Bcfe | [9] | 504.1 | 445.3 | 444 | |||
Natural Gas Equivalent | Proved Developed Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcfe | [9] | 373.3 | 388.2 | ||||
Proved reserves, ending balance | Bcfe | [9] | 402.2 | 373.3 | 388.2 | |||
Natural Gas Equivalent | Proved Undeveloped Reserves | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves, beginning balance | Bcfe | [9] | 72 | 55.8 | ||||
Proved reserves, ending balance | Bcfe | [9] | 101.9 | [8] | 72 | 55.8 | ||
[1] | Primarily related to upward revisions of 13.8 MMBoe at our Mahogany field and of 5.4 MMBoe at our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions. | ||||||
[2] | Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions. | ||||||
[3] | Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Virgo field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. | ||||||
[4] | Primarily related to extensions and discoveries of 1.3 MMBoe at our Virgo field and 0.7 MMBoe at our Ewing Bank 910 field. | ||||||
[5] | Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. | ||||||
[6] | Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg). | ||||||
[7] | Primarily related to conveyance of interest in properties related to the JV Drilling Program. | ||||||
[8] | We believe that we will be able to develop all but 1.8 MMBoe (approximately 11%) of the total of 17.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2018, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one in each field, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2021 and 2022, respectively. | ||||||
[9] | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. |
Supplemental Oil and Gas Disc_9
Supplemental Oil and Gas Disclosures - Estimated Quantities of Net Proved, Proved Developed and Proved Undeveloped Oil, NGLs and Natural Gas Reserves (Parenthetical) (Details) - MMBoe | 12 Months Ended | |||||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 6.2 | 14.2 | ||||||
Proved undeveloped reserves, that will not be developed within five years | 1.8 | |||||||
Percentage of proved undeveloped reserves that will be developed within five years | 11.00% | |||||||
Barrel Equivalent | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | [2] | 21.1 | [1] | 9.6 | [3] | 13 | [4] | |
Extensions and discoveries | [2] | 2.1 | [5] | 5.2 | [6] | |||
Proved reserves | [2] | 84 | 74.2 | 74 | 76.4 | |||
Barrel Equivalent | Proved Undeveloped Reserves | ||||||||
Reserve Quantities [Line Items] | ||||||||
Proved reserves | [2] | 17 | [7] | 12 | 9.3 | |||
Changes at the Viosca Knoll 823 | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 3.8 | |||||||
Extensions and discoveries | 1.3 | |||||||
Changes at the Fairway Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 1 | 1.5 | ||||||
Changes at the Mississippi Canyon 782 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 1.3 | |||||||
Changes at the Main Pass 108 field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 1.2 | |||||||
Changes Due To Price | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 2.3 | 3.4 | 1.2 | |||||
Mississippi Canyon 698 (Big Bend) | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 1.1 | |||||||
Ewing Bank 910 Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.8 | |||||||
Extensions and discoveries | 0.7 | |||||||
Viosca Knoll 783 (Tahoe/SE Tahoe) Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 0.8 | |||||||
Changes at Ship Shoal 349 Field (Mahogany) | ||||||||
Reserve Quantities [Line Items] | ||||||||
Extensions and discoveries | 3.5 | |||||||
Main Pass 286 Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Extensions and discoveries | 1.5 | |||||||
Mahogany Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 13.8 | |||||||
Ship Shoal 028 Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Revisions of previous estimates | 5.4 | |||||||
Mississippi Canyon 243 Field | ||||||||
Reserve Quantities [Line Items] | ||||||||
Wells expected to be drilled, year | 2,021 | |||||||
Virgo Deepwater Fields | ||||||||
Reserve Quantities [Line Items] | ||||||||
Wells expected to be drilled, year | 2,022 | |||||||
[1] | Primarily related to upward revisions of 13.8 MMBoe at our Mahogany field and of 5.4 MMBoe at our Ship Shoal 028 field. Additionally, increases of 2.3 MMBoe were due to price revisions. | |||||||
[2] | The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ significantly. | |||||||
[3] | Primarily related to upward revisions of 6.2 MMBoe, which included upwards revisions of 1.1 MMBoe at our Mississippi Canyon 698 (Big Bend) field, 1.0 MMBoe at our Fairway field, 0.8 MMBoe at our Ewing Bank 910 field and 0.8 MMBoe at our Viosca Knoll 783 (Tahoe/SE Tahoe) field. Additionally, increases of 3.4 MMBoe were due to price revisions. | |||||||
[4] | Primarily related to upward revisions of 14.2 MMBoe, which included upward revisions of 3.8 MMBoe at our Virgo field, 1.5 MMBoe at our Fairway field, 1.3 MMBoe at our Mississippi Canyon 782 (Dantzler) field, and 1.2 MMBoe at our Main Pass 108 field. Partially offsetting were decreases for price revisions of 1.2 MMBoe. | |||||||
[5] | Primarily related to extensions and discoveries of 1.3 MMBoe at our Virgo field and 0.7 MMBoe at our Ewing Bank 910 field. | |||||||
[6] | Primarily related to extensions and discoveries at our Ship Shoal 349 (Mahogany) field of 3.5 MMBoe and at our Main Pass 286 field of 1.5 MMBoe. | |||||||
[7] | We believe that we will be able to develop all but 1.8 MMBoe (approximately 11%) of the total of 17.0 MMBoe reserves classified as proved undeveloped (“PUDs”) at December 31, 2018, within five years from the date such reserves were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (Matterhorn) and Virgo deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Two sidetrack PUD locations, one in each field, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2021 and 2022, respectively. |
Supplemental Oil and Gas Dis_10
Supplemental Oil and Gas Disclosures - Schedule of Prices Weighted by Field Production Related to Proved Reserves (Details) | 12 Months Ended | |||
Dec. 31, 2018$ / Boe$ / Mcf | Dec. 31, 2017$ / Boe$ / Mcf | Dec. 31, 2016$ / Boe$ / Mcf | Dec. 31, 2015$ / Boe$ / Mcf | |
Oil | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | 65.21 | 46.58 | 36.28 | 46.94 |
NGLs | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | 29.73 | 22.65 | 16.82 | 17.60 |
Natural Gas | ||||
Reserve Quantities [Line Items] | ||||
Weighted price | $ / Mcf | 3.13 | 2.86 | 2.47 | 2.50 |
Supplemental Oil and Gas Dis_11
Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Standardized Measure of Discounted Future Net Cash Flows | ||||||
Future cash inflows | $ 3,500,900,000 | $ 2,328,800,000 | $ 1,818,400,000 | |||
Production | (958,500,000) | (813,800,000) | (691,500,000) | |||
Development | (272,400,000) | (157,400,000) | (141,100,000) | |||
Dismantlement and abandonment | (355,900,000) | (361,900,000) | (427,700,000) | |||
Income taxes | (293,900,000) | [1] | (74,800,000) | [1] | 0 | |
Future net cash inflows before 10% discount | 1,620,200,000 | 920,900,000 | 558,100,000 | |||
10% annual discount factor | (553,200,000) | (180,300,000) | (79,800,000) | |||
Standardized measure of discounted future net cash flows | $ 1,067,000,000 | $ 740,600,000 | $ 478,300,000 | $ 613,900,000 | ||
[1] | No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality. |
Supplemental Oil and Gas Dis_12
Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Extractive Industries [Abstract] | |||||
Income taxes | $ (293,900,000) | [1] | $ (74,800,000) | [1] | $ 0 |
[1] | No future income taxes were estimated for 2016 as our tax position had sufficient tax basis to offset estimated future taxes. State income taxes were disregarded due to immateriality. |
Supplemental Oil and Gas Dis_13
Supplemental Oil and Gas Disclosures - Change in Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in Standardized Measure | |||
Changes in Standardized Measure, beginning of year | $ 740.6 | $ 478.3 | $ 613.9 |
Sales and transfers of oil and gas produced, net of production costs | (398.1) | (315.3) | (218.6) |
Net changes in price, net of future production costs | 571.5 | 288 | (275.2) |
Extensions and discoveries, net of future production and development costs | 53.6 | 119.3 | |
Changes in estimated future development costs | (114.7) | (38.9) | (32.5) |
Previously estimated development costs incurred | 48.4 | 102.8 | 114.5 |
Revisions of quantity estimates | 307.6 | 106.4 | 190.1 |
Accretion of discount | 50.5 | 30.2 | 52.6 |
Net change in income taxes | (133.4) | (54.7) | |
Purchases of reserves in-place | 27.8 | ||
Sales of reserves in-place | (54.1) | ||
Changes in production rates due to timing and other | (32.7) | 24.5 | 33.5 |
Net increase (decrease) in standardized measure | 326.4 | 262.3 | (135.6) |
Changes in Standardized measure, end of year | $ 1,067 | $ 740.6 | $ 478.3 |