Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document And Company Information [Abstract] | |||
Entity Registrant Name | Denbury Resources Inc. | ||
Trading Symbol | DNR | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Central Index Key | 945,764 | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Public Float | $ 603,083,628 | ||
Entity Common Stock, Shares Outstanding | 401,918,775 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Current assets | |||
Cash and cash equivalents | $ 58 | $ 1,606 | |
Accrued production receivable | 146,334 | 124,936 | |
Trade and other receivables, net | 45,193 | 43,900 | |
Other current assets | 10,670 | 10,684 | |
Total current assets | 202,255 | 181,126 | |
Oil and natural gas properties (using full cost accounting) | |||
Proved properties | 10,775,792 | 10,419,827 | |
Unevaluated properties | 951,397 | 927,819 | |
CO2 properties | 1,191,058 | 1,188,467 | |
Pipelines and plants | 2,286,047 | 2,285,812 | |
Other property and equipment | 339,218 | 378,776 | |
Less accumulated depletion, depreciation, amortization and impairment | (11,376,646) | (11,212,327) | |
Net property and equipment | 4,166,866 | 3,988,374 | |
Other assets | 102,178 | 105,078 | |
Total assets | 4,471,299 | 4,274,578 | |
Current liabilities | |||
Accounts payable and accrued liabilities | 177,220 | 200,266 | |
Oil and gas production payable | 76,588 | 80,585 | |
Derivative liabilities | 99,061 | 69,279 | |
Current maturities of long-term debt (including future interest payable of $75,347 and $50,349, respectively – see Note 5) | 105,188 | [1] | 83,366 |
Total current liabilities | 458,057 | 433,496 | |
Long-term liabilities | |||
Long-term debt, net of current portion (including future interest payable of $241,472 and $178,476, respectively – see Note 5) | 2,979,086 | 2,909,732 | |
Asset retirement obligations | 165,756 | 146,807 | |
Deferred tax liabilities, net | 198,099 | 293,878 | |
Other liabilities | 22,136 | 22,217 | |
Total long-term liabilities | 3,365,077 | 3,372,634 | |
Commitments and contingencies (Note 11) | |||
Stockholders' equity | |||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding | 0 | 0 | |
Common stock, $.001 par value, 600,000,000 shares authorized; 402,549,346 and 402,334,655 shares issued, respectively | 403 | 402 | |
Paid-in capital in excess of par | 2,507,828 | 2,534,670 | |
Accumulated deficit | (1,855,810) | (2,018,989) | |
Treasury stock, at cost, 457,041 and 3,906,877 shares, respectively | (4,256) | (47,635) | |
Total stockholders' equity | 648,165 | 468,448 | |
Total liabilities and stockholders' equity | $ 4,471,299 | $ 4,274,578 | |
[1] | Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Stockholders' equity | |||
Preferred stock, par value | $ 0.001 | $ 0.001 | |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 | |
Preferred stock, shares issued | 0 | 0 | |
Preferred stock, shares outstanding | 0 | 0 | |
Common stock, par value | $ 0.001 | $ 0.001 | |
Common stock, shares authorized | 600,000,000 | 600,000,000 | |
Common stock, shares issued | 402,549,346 | 402,334,655 | |
Treasury stock, shares | 457,041 | 3,906,877 | |
Debt Instrument [Line Items] | |||
Future interest payable - current | $ 105,188 | [1] | $ 83,366 |
Future interest payable - long-term | 2,979,086 | 2,909,732 | |
Future interest payable on senior secured and convertible senior notes | |||
Debt Instrument [Line Items] | |||
Future interest payable - current | 75,347 | 50,349 | |
Future interest payable - long-term | $ 241,472 | $ 178,476 | |
[1] | Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues and other income | |||
Oil, natural gas, and related product sales | $ 1,089,666 | $ 935,751 | $ 1,213,026 |
CO2 sales and transportation fees | 26,182 | 24,816 | 30,626 |
Interest income and other income | 13,938 | 15,029 | 13,908 |
Total revenues and other income | 1,129,786 | 975,596 | 1,257,560 |
Expenses | |||
Lease operating expenses | 447,799 | 414,937 | 515,043 |
Marketing and plant operating expenses | 51,820 | 57,454 | 55,746 |
CO2 discovery and operating expenses | 3,099 | 3,374 | 4,557 |
Taxes other than income | 87,207 | 77,892 | 109,992 |
General and administrative expenses | 101,806 | 109,926 | 144,564 |
Interest, net of amounts capitalized of $30,762, $25,982 and $32,146, respectively | 99,263 | 125,145 | 159,268 |
Depletion, depreciation, and amortization | 207,713 | 846,043 | 531,660 |
Commodity derivatives expense (income) | 77,576 | 127,944 | (147,999) |
Gain on debt extinguishment | 0 | (115,095) | 0 |
Write-down of oil and natural gas properties | 0 | 810,921 | 4,939,600 |
Impairment of goodwill | 0 | 0 | 1,261,512 |
Other expenses | 7,003 | 37,402 | 9,599 |
Total expenses | 1,083,286 | 2,495,943 | 7,583,542 |
Income (loss) before income taxes | 46,500 | (1,520,347) | (6,325,982) |
Income tax benefit | (116,652) | (544,170) | (1,940,534) |
Net income (loss) | $ 163,152 | $ (976,177) | $ (4,385,448) |
Net income (loss) per common share | |||
Basic | $ 0.42 | $ (2.61) | $ (12.57) |
Diluted | 0.41 | (2.61) | (12.57) |
Dividends declared per common share | $ 0 | $ 0 | $ 0.1875 |
Weighted average common shares outstanding | |||
Basic | 390,928 | 373,859 | 348,802 |
Diluted | 395,921 | 373,859 | 348,802 |
Consolidated Statements of Ope5
Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Expenses | |||
Capitalized Interest | $ 30,762 | $ 25,982 | $ 32,146 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Operations - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net income (loss) | $ 163,152 | $ (976,177) | $ (4,385,448) |
Other comprehensive income, net of income tax | |||
Interest rate lock derivative contracts reclassified to income, net of tax of $0, $0 and $128, respectively | 0 | 0 | 209 |
Total other comprehensive income | 0 | 0 | 209 |
Comprehensive income (loss) | $ 163,152 | $ (976,177) | $ (4,385,239) |
Consolidated Statements of Com7
Consolidated Statements of Comprehensive Operations (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other comprehensive income, net of income tax | |||
Tax for interest rate lock derivative contracts reclassified to income | $ 0 | $ 0 | $ 128 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities | |||
Net income (loss) | $ 163,152 | $ (976,177) | $ (4,385,448) |
Adjustments to reconcile net income (loss) to cash flows from operating activities | |||
Depletion, depreciation, and amortization | 207,713 | 846,043 | 531,660 |
Write-down of oil and natural gas properties | 0 | 810,921 | 4,939,600 |
Impairment of goodwill | 0 | 0 | 1,261,512 |
Deferred income taxes | (95,779) | (543,385) | (1,932,179) |
Stock-based compensation | 15,154 | 14,995 | 30,604 |
Commodity derivatives expense (income) | 77,576 | 127,944 | (147,999) |
Receipt (payment) on settlements of commodity derivatives | (47,795) | 84,181 | 511,699 |
Gain on debt extinguishment | 0 | (115,095) | 0 |
Debt issuance costs and discounts | 6,191 | 17,006 | 9,121 |
Other, net | 3,112 | (2,161) | 343 |
Changes in assets and liabilities, net of effects from acquisitions | |||
Accrued production receivable | (21,398) | (24,290) | 81,213 |
Trade and other receivables | (4,421) | 35,923 | 67,047 |
Other current and long-term assets | (1,722) | (8,661) | 241 |
Accounts payable and accrued liabilities | (24,710) | (34,240) | (55,234) |
Oil and natural gas production payable | (3,997) | (6,752) | (40,833) |
Other liabilities | (5,933) | (7,029) | (7,043) |
Net cash provided by operating activities | 267,143 | 219,223 | 864,304 |
Cash flows from investing activities | |||
Oil and natural gas capital expenditures | (262,867) | (243,027) | (476,398) |
Acquisitions of oil and natural gas properties | (88,886) | (1,310) | (21,876) |
CO2 capital expenditures | (2,159) | (2,321) | (26,301) |
Pipelines and plants capital expenditures | (2,540) | (2,666) | (31,728) |
Net proceeds from sales of oil and natural gas properties and equipment | 1,696 | 47,725 | 563 |
Other | (2,548) | (3,818) | 5,555 |
Net cash used in investing activities | (357,304) | (205,417) | (550,185) |
Cash flows from financing activities | |||
Bank repayments | (1,589,000) | (1,730,500) | (1,862,000) |
Bank borrowings | 1,763,000 | 1,856,500 | 1,642,000 |
Interest payments on senior secured notes treated as a reduction of debt | (50,349) | (25,835) | 0 |
Repayment or repurchases of senior subordinated notes | (2,503) | (76,708) | (485) |
Pipeline financing and capital lease debt repayments | (27,462) | (28,849) | (33,642) |
Cash dividends paid | (275) | (486) | (65,426) |
Other | (4,798) | (9,134) | (14,907) |
Net cash provided by (used in) financing activities | 88,613 | (15,012) | (334,460) |
Net decrease in cash and cash equivalents | (1,548) | (1,206) | (20,341) |
Cash and cash equivalents at beginning of year | 1,606 | 2,812 | 23,153 |
Cash and cash equivalents at end of year | $ 58 | $ 1,606 | $ 2,812 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock ($.001 Par Value) | Paid-In Capital in Excess of Par | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Treasury Stock (at cost) |
Beginning balance, shares at Dec. 31, 2014 | 411,779,911 | 58,415,507 | ||||
Beginning balance at Dec. 31, 2014 | $ 5,703,856 | $ 412 | $ 3,230,418 | $ 3,392,465 | $ (209) | $ (919,230) |
Stock Repurchase Program, shares | 4,424,702 | |||||
Stock Repurchase Program, value | (11,759) | $ (11,759) | ||||
Issued or purchased pursuant to stock compensation plans, shares | 3,900,127 | |||||
Issued or purchased pursuant to stock compensation plans, value | 567 | $ 5 | 562 | |||
Issued pursuant to employee stock purchase plan, shares | (353,480) | |||||
Issued pursuant to employee stock purchase plan, value | 2,667 | (2,867) | $ 5,534 | |||
Issued pursuant to directors' compensation plan, shares | 292,407 | |||||
Issued pursuant to directors' compensation plan, value | 398 | 398 | ||||
Share correction, shares | (1,430,819) | |||||
Share correction, value | (22,078) | $ (2) | (22,076) | |||
Stock-based compensation | 39,285 | 39,285 | ||||
Income tax shortfall from equity awards | (8,102) | (8,102) | ||||
Tax withholding - stock compensation, shares | 637,582 | |||||
Tax withholding - stock compensation, value | (4,712) | $ (4,712) | ||||
Derivative contracts, net | 209 | 209 | ||||
Retirement of treasury stock, shares | (60,000,000) | (60,000,000) | ||||
Retirement of treasury stock, value | 0 | $ (60) | (884,069) | $ 884,129 | ||
Cash dividends declared ($0.1875 per common share) | (65,971) | (65,971) | ||||
Net income (loss) | (4,385,448) | (4,385,448) | ||||
Ending balance, shares at Dec. 31, 2015 | 354,541,626 | 3,124,311 | ||||
Ending balance at Dec. 31, 2015 | 1,248,912 | $ 355 | 2,353,549 | (1,058,954) | 0 | $ (46,038) |
Cumulative effect of accounting change | 15,657 | (415) | 16,072 | |||
Issued or purchased pursuant to stock compensation plans, shares | 7,031,767 | |||||
Issued or purchased pursuant to stock compensation plans, value | 0 | $ 7 | (7) | |||
Issued pursuant to directors' compensation plan, shares | 31,930 | |||||
Issued pursuant to directors' compensation plan, value | 50 | 50 | ||||
Issued as part of debt exchange, shares | 40,729,332 | |||||
Issued as part of debt exchange, value | 160,491 | $ 40 | 160,451 | |||
Stock-based compensation | 21,042 | 21,042 | ||||
Tax withholding - stock compensation, shares | 782,566 | |||||
Tax withholding - stock compensation, value | (1,597) | $ (1,597) | ||||
Retirement of treasury stock, value | $ 0 | |||||
Dividends adjustments | 70 | 70 | ||||
Net income (loss) | $ (976,177) | (976,177) | ||||
Ending balance, shares at Dec. 31, 2016 | 402,334,655 | 402,334,655 | 3,906,877 | |||
Ending balance at Dec. 31, 2016 | $ 468,448 | $ 402 | 2,534,670 | (2,018,989) | 0 | $ (47,635) |
Issued or purchased pursuant to stock compensation plans, shares | 5,201,854 | |||||
Issued or purchased pursuant to stock compensation plans, value | 0 | $ 6 | (6) | |||
Issued pursuant to directors' compensation plan, shares | 12,837 | |||||
Issued pursuant to directors' compensation plan, value | 0 | 0 | ||||
Stock-based compensation | 19,721 | 19,721 | ||||
Tax withholding - stock compensation, shares | 1,550,164 | |||||
Tax withholding - stock compensation, value | (3,183) | $ (3,183) | ||||
Retirement of treasury stock, shares | (5,000,000) | (5,000,000) | ||||
Retirement of treasury stock, value | 0 | $ (5) | (46,557) | $ 46,562 | ||
Dividends adjustments | 27 | 27 | ||||
Net income (loss) | $ 163,152 | 163,152 | ||||
Ending balance, shares at Dec. 31, 2017 | 402,549,346 | 402,549,346 | 457,041 | |||
Ending balance at Dec. 31, 2017 | $ 648,165 | $ 403 | $ 2,507,828 | $ (1,855,810) | $ 0 | $ (4,256) |
Consolidated Statements of Ch10
Consolidated Statements of Changes in Stockholders' Equity (Parentheticals) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Stockholders' Equity [Abstract] | |||
Common stock cash dividend per share | $ 0 | $ 0 | $ 0.1875 |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | Note 1. Significant Accounting Policies Organization and Nature of Operations Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations. Principles of Reporting and Consolidation The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO 2 reserves used to compute depletion of CO 2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; and (8) estimates made in the calculation of income taxes. While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity. Cash Equivalents We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. Oil and Natural Gas Properties Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $21.4 million , $21.0 million and $17.9 million during the years ended December 31, 2017, 2016 and 2015, respectively, whereby these costs were transferred to the full cost amortization base. Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves declined throughout 2015 and 2016 and led to our recognizing full cost pool ceiling test write-downs totaling $810.9 million and $4.9 billion during 2016 and 2015, respectively. We did not record any ceiling test write-down during 2017. Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables. Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion. CO 2 Properties We own and produce CO 2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO 2 to third parties when it is produced and sold. Expenses related to the production of CO 2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO 2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO 2 (see Tertiary Injection Costs above for further discussion). Costs incurred to search for CO 2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO 2 properties” on our Consolidated Balance Sheets. Capitalized CO 2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. Pipelines and Plants CO 2 used in our tertiary floods is transported to our fields through CO 2 pipelines. Costs of CO 2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years . Capitalized costs include $101.1 million of CO 2 pipelines as of December 31, 2017, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2017. Pipelines and plants also include capitalized costs associated with the Riley Ridge gas processing facility in southwestern Wyoming. During the fourth quarter of 2016, we reassessed the estimated useful life of the gas processing facility and related assets, due to the extended shut-in status of the Riley Ridge gas processing facility and our analysis of cost estimates and engineering options to remedy certain existing issues, and recorded accelerated depreciation to fully depreciate capitalized costs related to the facility and intangible assets assigned to helium production rights at Riley Ridge. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years , and computer equipment and software are generally depreciated over a useful life of three to five years . Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term. Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the lease term. Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred. Goodwill and Other Intangible Assets Goodwill previously recorded on our Consolidated Balance Sheets represented the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of businesses. Goodwill was not amortized; rather, it was tested for impairment annually during the fourth quarter or when events or changes in circumstances indicated that it was more likely than not the fair value of a reporting unit with goodwill was reduced below its carrying value. Because the fair value of the reporting unit (enterprise value) did not exceed the fair value of assets and liabilities, we recorded a goodwill impairment charge of $1.3 billion during 2015 to fully impair the carrying value of our goodwill. Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming and is included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO 2 contract intangible asset on a straight-line basis over the contract term. Total amortization expense for our intangible assets was $2.4 million and $2.3 million during the years ended December 31, 2017 and 2016 . The following table summarizes the carrying value of our intangible assets as of December 31, 2017 and 2016 : December 31, In thousands 2017 2016 Intangible asset value $ 37,848 $ 37,848 Accumulated amortization (10,645 ) (8,215 ) Net book value $ 27,203 $ 29,633 As of December 31, 2017 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2018 $ 2,430 2019 2,430 2020 2,430 2021 2,430 2022 2,430 Impairment Assessment of Long-Lived Assets The portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2017. Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO 2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. Asset retirement obligations are estimated at the present value of expected future net cash flows. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic. Commodity Derivative Contracts We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change. Concentrations of Credit Risk Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). There are no margin requirements with the counterparties of our derivative contracts. Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any purchaser to have a material adverse effect upon our operations. For the years ended December 31, 2017 , 2016 and 2015 , two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP ( 22% , 20% and 15% in 2017 , 2016 and 2015 , respectively) and Marathon Petroleum Company ( 10% , 14% and 28% in 2017 , 2016 and 2015 , respectively). Revenue Recognition Revenue Recognition. Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivable. We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2017 and 2016 , our aggregate oil and natural gas imbalances were not material to our consolidated financial statements. We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date. Other Receivables Denbury, along with other companies, has supported the development of a proposed plant in the Gulf Coast for which one of the by-products would be CO 2 , and for which Denbury has an offtake agreement. Since early 2015, we have made successive loans towards this development, which totaled approximately $17 million at December 31, 2017. We have recorded these amounts as a loan receivable in “Trade and other receivables, net” on our Consolidated Balance Sheets. We understand the project is supported by multiple offtake agreements of various products and loans from several other interested parties and fixed prices have been agreed upon for engineering, procurement and construction services. The project developer is currently soliciting potential lead equity investors for the project, and we have been informed that a determination on a lead equity investor is targeted for mid-2018. If the project developer is unable to secure the required equity investment, we may be required to impair the loan. Income Taxes Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, stock options, stock appreciation rights (“SARs”), nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible. The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Year Ended December 31, In thousands 2017 2016 2015 Numerator Net income (loss) – basic $ 163,152 $ (976,177 ) $ (4,385,448 ) Effect of potentially dilutive securities Interest on convertible senior notes 49 — — Net income (loss) – diluted $ 163,201 $ (976,177 ) $ (4,385,448 ) Denominator Weighted average common shares outstanding – basic 390,928 373,859 348,802 Effect of potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards 2,242 — — Convertible senior notes 2,751 — — Weighted average common shares outstanding – diluted 395,921 373,859 348,802 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the year ended December 31, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of the period. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2017 2016 2015 Stock options and SARs 4,512 6,427 9,619 Restricted stock and performance-based equity awards 5,645 5,816 3,867 Environmental and Litigation Contingencies The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors. Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain. Recent Accounting Pronouncements Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale , for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows. Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management has substantially completed the evaluation of our various revenue contracts. Based on the work performed to date, we do not believe the standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures. |
Asset Acquisition and Assets He
Asset Acquisition and Assets Held for Sale | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Asset Acquisition and Assets Held for Sale | Note 2. Asset Acquisition and Assets Held for Sale Asset Acquisition On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $ 71.5 million , before customary closing adjustments. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties. Assets Held for Sale We began actively marketing for sale certain non-productive surface acreage in the Houston area during July 2017, which we currently anticipate selling during 2018. As of December 31, 2017, the carrying value of the land held for sale was $ 33.1 million , which is included in “Other property and equipment” on our Consolidated Balance Sheets. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 3. Asset Retirement Obligations The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2017 and 2016 : Year Ended December 31, In thousands 2017 2016 Beginning asset retirement obligations $ 149,120 $ 145,696 Liabilities incurred and assumed during period 2,698 5,383 Revisions in estimated retirement obligations 6,867 6,238 Liabilities settled and sold during period (5,617 ) (19,878 ) Accretion expense 13,242 11,681 Ending asset retirement obligations 166,310 149,120 Less: current asset retirement obligations (1) (554 ) (2,313 ) Long-term asset retirement obligations $ 165,756 $ 146,807 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. Liabilities assumed relate to minor acquisitions, with liabilities incurred generally relating to wells and facilities. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $40.6 million and $39.3 million as of December 31, 2017 and 2016 , respectively. These balances are primarily invested in U.S. Treasury bonds, are recorded at amortized cost and are included in “Other assets” in our Consolidated Balance Sheets. The carrying value of these investments approximates their estimated fair market value as of December 31, 2017 and 2016 . |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment Disclosure [Text Block] | Note 4. Property and Equipment A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2017 , and the year in which the costs were incurred follows: December 31, 2017 Costs Incurred During: In thousands 2017 2016 2015 2014 and Prior Total Property acquisition costs $ 8,527 $ — $ — $ 583,418 $ 591,945 Exploration and development 6,948 20,675 24,470 165,419 217,512 Capitalized interest 30,762 25,220 28,303 57,655 141,940 Total $ 46,237 $ 45,895 $ 52,773 $ 806,492 $ 951,397 Our property acquisition costs for 2014 and prior were primarily related to the fair value allocated to the purchase of interests in the Cedar Creek Anticline (“CCA”) and Hartzog Draw, as well as CO 2 tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2017. The most significant development costs incurred during each period relate to development in preparation for the CO 2 floods at Webster and Grieve fields. We have not yet recognized proved tertiary reserves in these fields. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at lea st annually. We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten years . Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Note 5. Long-Term Debt The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2017 and 2016 , and does not reflect transactions in the January 2018 exchange of $174.3 million of our existing senior subordinated notes for an aggregate $133.5 million of additional 9¼% Senior Secured Second Lien Notes due 2022 and new 5% Convertible Senior Notes due 2023 (see December 2017 and January 2018 Note Exchanges below): December 31, In thousands 2017 2016 Senior Secured Bank Credit Agreement $ 475,000 $ 301,000 9% Senior Secured Second Lien Notes due 2021 614,919 614,919 9¼% Senior Secured Second Lien Notes due 2022 381,568 — 3½% Convertible Senior Notes due 2024 84,650 — 6⅜% Senior Subordinated Notes due 2021 215,144 215,144 5½% Senior Subordinated Notes due 2022 408,882 772,912 4⅝% Senior Subordinated Notes due 2023 376,501 622,297 Other Senior Subordinated Notes, including premium of $0 and $3, respectively — 2,253 Pipeline financings 192,429 202,671 Capital lease obligations 26,298 48,718 Total debt principal balance 2,775,391 2,779,914 Future interest payable (1) 316,818 228,825 Debt issuance costs (7,935 ) (15,641 ) Total debt, net of debt issuance costs 3,084,274 2,993,098 Less: current maturities of long-term debt (1) (105,188 ) (83,366 ) Long-term debt and capital lease obligations $ 2,979,086 $ 2,909,732 (1) Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors . Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior secured, senior, and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries. Senior Secured Bank Credit Facility In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million , which may be increased at the sole discretion of the administrative agent, and short-term swingline loans are available in an aggregate amount not to exceed $25 million , each subject to the available commitments under the Bank Credit Agreement. The Bank Credit Agreement is guaranteed jointly and severally by each subsidiary of DRI that is 100% owned, directly or indirectly, by DRI and is secured by (1) a significant portion of our proved oil and natural gas properties held through DRI’s restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of commodity derivative agreements of DRI and such subsidiaries (as applicable); and (4) a pledge of deposit accounts, securities accounts and commodity accounts of DRI and such subsidiaries (as applicable). The Bank Credit Agreement limits our ability to, among other things, incur and repay indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make distributions and dividends; and enter into commodity derivative agreements, in each case subject to customary exceptions. As of December 31, 2017, the borrowing base and lender commitments for the revolving credit facility were $1.05 billion , and scheduled redeterminations of the borrowing base are to occur semiannually, with the next such redetermination being scheduled for May 2018. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. As amended, the Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following: • A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio; • A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and • A requirement to maintain a current ratio of 1.0 to 1.0. As of December 31, 2017, (1) loans under the Bank Credit Agreement were subject to varying rates of interest based on either (a) for ABR Loans, a base rate determined under the Bank Credit Agreement (the “ABR”) plus an applicable margin ranging from 1.5% to 2.5% per annum, or (b) for LIBOR Loans, the LIBOR rate plus an applicable margin ranging from 2.5% to 3.5% per annum (capitalized terms as defined in the Bank Credit Agreement) and (2) the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement was subject to a commitment fee of 0.50% . As of December 31, 2017, we were in compliance with all debt covenants under the Bank Credit Agreement. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 4.5% and 3.0% as of December 31, 2017 and 2016, respectively. The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC. December 2017 and January 2018 Note Exchanges During December 2017, we entered into privately negotiated agreements to exchange a total of $609.8 million aggregate principal amount of our existing senior subordinated notes for $381.6 million aggregate principal amount of new 2022 Senior Secured Notes and $84.7 million aggregate principal amount of new 2024 Convertible Senior Notes, resulting in a net reduction in our debt principal from these exchanges of $143.6 million . The exchanged notes consisted of $364.0 million aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 (the “2022 Notes”) and $245.8 million aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023 (the “2023 Notes”). During January 2018, we closed additional transactions to exchange a total of $174.3 million aggregate principal amount of our existing senior subordinated notes for $74.1 million aggregate principal amount of new 2022 Senior Secured Notes and $59.4 million aggregate principal amount of new 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”), resulting in a net reduction in our debt principal from these exchanges of $40.8 million . The exchanged notes consisted of $11.6 million aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021 (the “2021 Notes”), $94.2 million aggregate principal amount of our 2022 Notes and $68.5 million aggregate principal amount of our 2023 Notes. In accordance with FASC 470-60, the exchanges were accounted for as a troubled debt restructuring due to the level of concession provided by our senior subordinated note holders. Under this guidance, future interest applicable to the 2022 Senior Secured Notes and 2024 Convertible Senior Notes is recorded as debt up to the point that the principal and future interest of the new notes is equal to the principal amount of the extinguished notes, rather than recognizing a gain on extinguishment for this amount. As of December 31, 2017, $138.3 million of future interest on the 2022 Senior Secured Notes and 2024 Convertible Senior Notes was recorded as debt, which will be reduced as semiannual interest payments are made, with the remaining $32.3 million of future interest to be recognized as interest expense over the term of these notes. Therefore, future interest expense reflected in our Consolidated Statements of Operations on the 2022 Senior Secured Notes and 2024 Convertible Senior Notes will be significantly lower than the actual cash interest payments. 2016 Senior Subordinated Notes Exchange During May 2016, we entered into privately negotiated agreements to exchange a total of $1,057.8 million of our existing senior subordinated notes for $614.9 million principal amount of our 2021 Senior Secured Notes plus 40.7 million shares of Denbury common stock, resulting in a net reduction from these exchanges of $442.9 million in our debt principal. As a result of this debt exchange , we recognized a gain of $12.0 million during the year ended December 31, 2016, which is included in “Gain on debt extinguishment” in the accompanying Consolidated Statements of Operations. Senior Secured Second Lien Notes 9% Senior Secured Second Lien Notes due 2021. In May 2016, we issued $614.9 million of 2021 Senior Secured Notes. The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of existing senior subordinated notes (see 2016 Senior Subordinated Notes Exchange above). The 2021 Senior Secured Notes mature on May 15, 2021, and interest is payable semiannually in arrears on May 15 and November 15 of each year, beginning in November 2016. We may redeem the 2021 Senior Secured Notes in whole or in part at our option beginning December 15, 2018, at a redemption price of 109% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2021 Senior Secured Notes. Prior to December 15, 2018, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Senior Secured Notes at a price of 109% of par with the proceeds of certain equity offerings. In addition, at any time prior to December 15, 2018, we may redeem the 2021 Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2021 Senior Secured Notes are not subject to any sinking fund requirements. The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. 9¼% Senior Secured Second Lien Notes due 2022. In December 2017 and January 2018, we issued $381.6 million and $74.1 million , respectively, of 2022 Senior Secured Notes. The 2022 Senior Secured Notes, which bear interest at a rate of 9.25% per annum, were issued at par in connection with exchanges with a limited number of holders of existing senior subordinated notes (see December 2017and January 2018 Note Exchanges above). The 2022 Senior Secured Notes mature on March 31, 2022, and interest is payable semiannually in arrears on March 31 and September 30 of each year, beginning in March 2018. We may redeem the 2022 Senior Secured Notes in whole or in part at our option beginning March 31, 2019, at a redemption price of 109.25% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2022 Senior Secured Notes. Prior to March 31, 2019, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2022 Senior Secured Notes at a price of 109.25% of par with the proceeds of certain equity offerings. In addition, at any time prior to March 31, 2019, we may redeem the 2022 Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2022 Senior Secured Notes are not subject to any sinking fund requirements. The 2022 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. Restrictive Covenants in Indentures for Senior Secured Second Lien Notes. Each of the indentures for the 2021 Senior Secured Notes and 2022 Senior Secured Notes contains customary covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (as defined in the indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). As of December 31, 2017, we were in compliance with all debt covenants under the indentures related to our senior secured second lien notes. Convertible Senior Notes 3½% Convertible Senior Notes due 2024. In December 2017, we issued $84.7 million of 2024 Convertible Senior Notes. The 2024 Convertible Senior Notes, which bear interest at a rate of 3.5% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of existing senior subordinated notes (see December 2017 and January 2018 Note Exchanges above). The 2024 Convertible Senior Notes mature on March 31, 2024, and interest is payable semiannually in arrears on March 31 and September 30 of each year, beginning in March 2018. We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity. The 2024 Convertible Senior Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 444.44 shares of common stock per $1,000 principal amount of 2024 Convertible Senior Notes, provided that the conversion rate will be 455.56 shares of common stock per $1,000 principal amount for 2024 Convertible Senior Notes converted prior to April 13, 2018, if any. The 2024 Convertible Senior Notes will be automatically converted into shares of common stock at a rate of 444.44 shares of $1,000 principal amount of 2024 Convertible Senior Notes if the volume weighted average price of the Company’s common stock equals or exceeds the threshold price, which initially is $2.65 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. The 2024 Convertible Senior Notes are convertible into between 37.6 and 38.6 million shares of the Company’s common stock. The 2024 Convertible Senior Notes are not subject to any sinking fund requirements. 5% Convertible Senior Notes due 2023. In January 2018, we issued $59.4 million of 2023 Convertible Senior Notes. The 2023 Convertible Senior Notes, which bear interest at a rate of 5% per annum, were issued at par in exchange offers with a limited number of holders of existing senior subordinated notes (see December 2017 and January 2018 Note Exchanges above). The 2023 Convertible Senior Notes mature on December 15, 2023, and interest is payable semiannually in arrears on June 15 and December 15 of each year, beginning in June 2018. We do not have the right to redeem the 2023 Convertible Senior Notes prior to their maturity. The 2023 Convertible Senior Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 281.69 shares of common stock per $1,000 principal amount of 2023 Convertible Senior Notes, subject to customary adjustments to the conversion rate and threshold price with respect to, among other things, stock dividends and distributions, mergers and reclassifications. The 2023 Convertible Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which initially is $3.55 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. Additionally, the Company may, based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to certain limitations, increase the conversion rate (which increase in conversion rate is limited until January 9, 2019 to no greater than 393.55 shares of common stock per $1,000 principal amount of 2023 Convertible Senior Notes). Any such conversion rate increase would cause a proportional decrease in the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion into common stock at a lower price than the initial or then-prevailing threshold price. Restrictive Covenants in Indentures for Convertible Senior Notes. Each of the indentures for the 2024 Convertible Senior Notes and 2023 Convertible Senior Notes contains customary covenants that restrict our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (as defined in the indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). As of December 31, 2017, we were in compliance with all debt covenants under the indentures related to our convertible senior notes. Senior Subordinated Notes 6⅜% Senior Subordinated Notes due 2021 . In February 2011, we issued $400 million of 2021 Notes. The 2021 Notes, which bear interest at a rate of 6.375% per annum, were sold at par. The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year. At any time prior to August 15, 2018, we may redeem the 2021 Notes in whole or in part at our option at a redemption price of 102.125% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. 5½% Senior Subordinated Notes due 2022. In April 2014, we issued $1.25 billion of 2022 Notes. The 2022 Notes, which bear interest at a rate of 5.5% per annum, were sold at par. The 2022 Notes mature on May 1, 2022, and interest is payable on May 1 and November 1 of each year. At any time prior to May 1, 2018, we may redeem the 2022 Notes in whole or in part at our option, at a redemption price of 104.125% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. The 2022 Notes are not subject to any sinking fund requirements. 4⅝% Senior Subordinated Notes due 2023 . In February 2013, we issued $1.2 billion of 2023 Notes. The 2023 Notes, which bear interest at a rate of 4.625% per annum, were sold at par. The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at a redemption price of 102.313% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. The 2023 Notes are not subject to any sinking fund requirements. Restrictive Covenants in Indentures for Senior Subordinated Notes. Each of the indentures for the 2021 Notes, 2022 Notes and 2023 Notes contains certain covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that the restricted payments covenant in the indentures for the 2022 and 2023 Notes (the “2022 and 2023 Indentures”) permits us in certain circumstances to make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (both as defined in the 2022 and 2023 Indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment), although we will not be able to realize the practical benefit of the restricted payment covenant flexibility in the 2022 and 2023 Indentures until the 2021 Notes have been redeemed or retired. As of December 31, 2017 , we were in compliance with all debt covenants under the indentures related to our senior subordinated notes. 2016 Repurchases of Senior Subordinated Notes. During 2016, we repurchased a total of $181.9 million of our outstanding long-term indebtedness, consisting of $9.8 million principal amount of our 2021 Notes, $66.1 million principal amount of our 2022 Notes, and $106.0 million principal amount of our 2023 Notes in open-market transactions for a total purchase price of $76.7 million , excluding accrued interest. In connection with these series of transactions, we recognized a $103.1 million gain on extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2016. Pipeline Financings In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The NEJD Pipeline system included a 20 -year financing lease, and the Free State Pipeline included a long-term transportation service agreement. These transactions are both accounted for as financing leases. Debt Issuance Costs In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the straight line or effective interest method over the term of each related facility or borrowing. Remaining unamortized debt issuance costs were $13.8 million and $24.7 million at December 31, 2017 and 2016 , respectively. Issuance costs associated with our Bank Credit Agreement are included in “Other assets” in our Consolidated Balance Sheets, and issuance costs associated with our senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in our Consolidated Balance Sheets. Indebtedness Repayment Schedule At December 31, 2017 , our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows: In thousands 2018 $ 29,841 2019 502,570 2020 16,283 2021 845,540 2022 808,733 Thereafter 572,424 Total indebtedness $ 2,775,391 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 6. Income Taxes Our income tax provision (benefit) is as follows: Year Ended December 31, In thousands 2017 2016 2015 Current income tax expense (benefit) Federal $ (19,485 ) $ — $ (8,515 ) State (1,388 ) (785 ) 160 Total current income tax benefit (20,873 ) (785 ) (8,355 ) Deferred income tax expense (benefit) Federal (113,863 ) (521,519 ) (1,853,517 ) State 18,084 (21,866 ) (78,662 ) Total deferred income tax benefit (95,779 ) (543,385 ) (1,932,179 ) Total income tax benefit $ (116,652 ) $ (544,170 ) $ (1,940,534 ) At December 31, 2017 , we had tax-effected federal net operating loss carryforwards (“NOLs”) totaling $18.6 million , state NOLs and tax credits totaling $51.5 million and $1.9 million , respectively (before provision for valuation allowance), an estimated $51.5 million of enhanced oil recovery credits to carry forward related to our tertiary operations, an estimated $21.6 million of research and development credits, and $20.3 million of alternative minimum tax credits. Under the Tax Cut and Jobs Act (“the Act”) signed by the President on December 22, 2017, all of our alternative minimum tax credits are fully refundable by 2021. We consider our assessment of the recorded tax benefit associated with the impacts of the Act to be substantially complete, which is reflected in the table reconciling income tax expense below. Uncertainty of potential state tax impacts of the Act, as well as additional regulatory guidance that may be issued, could result in further tax effects, which are not expected to be material to our financial statements. Our state NOLs expire in various years, starting in 2019, although most do not begin to expire until 2024. Our enhanced oil recovery credits and research and development credits begin to expire in 2024 and 2031, respectively. Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2017 and 2016 balance sheet dates. As of December 31, 2017 , we had $51.1 million of deferred tax assets associated with State of Louisiana and Mississippi net operating losses and tax credits. A tax valuation allowance was recorded in 2015 to reduce the carrying value of our Louisiana deferred tax assets as the result of a tax law enacted in the State of Louisiana, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards. As of December 31, 2017 tax valuation allowances totaling $35.3 million were recorded for our State of Louisiana deferred tax assets, a reduction of $1.3 million during 2017 due to adjustments of prior year balances. Based on recent losses from falling commodity prices and lower future forecasted income related to our Mississippi deferred tax assets, we concluded it was not more-likely-than-not that the deferred tax assets would be realized. Accordingly, we recorded a valuation allowance against our Mississippi deferred tax assets in the amount of $6.8 million during 2017. Furthermore, as a result of the Act, our deferred tax assets associated with State of Louisiana and Mississippi net operating losses and tax credits were increased by $9.1 million due to a reduction in the federal benefit of state taxes paid. This change was fully offset by an increase in the valuation allowance, resulting in a total increase in valuation allowance during 2017 of $14.6 million . The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. As of December 31, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of December 31, 2017. In connection with the transaction in which we exchanged a portion of our existing senior subordinated notes for senior secured and senior notes, we realized a tax gain due to the concession extended by our note holders during the second quarter of 2016 and fourth quarter of 2017. This tax gain was offset by net operating losses and other deferred tax asset attributes. Significant components of our deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows: December 31, In thousands 2017 2016 Deferred tax assets Loss carryforwards – federal $ 18,581 $ 27,078 Loss carryforwards – state 51,510 42,625 Tax credit carryover 20,270 41,132 Business credit carryforwards 74,914 72,748 Derivative contracts 23,024 27,261 Stock-based compensation 2,873 13,887 Unrecognized gain and original issue discount on debt exchange 85,951 108,659 Other 29,481 44,422 Valuation allowance (51,134 ) (36,510 ) Total deferred tax assets 255,470 341,302 Deferred tax liabilities Property and equipment (450,629 ) (628,359 ) Other (2,940 ) (6,821 ) Total deferred tax liabilities (453,569 ) (635,180 ) Total net deferred tax liability $ (198,099 ) $ (293,878 ) Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows: Year Ended December 31, In thousands 2017 2016 2015 Income tax provision (benefit) calculated using the federal statutory income tax rate $ 16,275 $ (532,121 ) $ (2,214,094 ) State income taxes, net of federal income tax benefit 2,764 (25,351 ) (117,624 ) Impairment of goodwill with no related tax basis — — 363,666 Tax shortfall on stock-based compensation deduction 5,567 9,557 — Valuation allowance 5,562 2,910 33,600 Enhanced oil recovery tax credits generated (11,307 ) — — Re-measurement of deferreds related to federal tax rate change (132,224 ) — — Other (3,289 ) 835 (6,082 ) Total income tax benefit $ (116,652 ) $ (544,170 ) $ (1,940,534 ) We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions. The statutes of limitation for our income tax returns for tax years ending prior to 2014 have lapsed and therefore are not available for examination by respective taxing authorities. The statute of limitations for tax year 2012 remains open as a result of our 2014 carryback claim. We have not paid any significant interest or penalties associated with our income taxes. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity | Note 7. Stockholders’ Equity 401(k) Plan We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations. We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately. During 2017 , 2016 and 2015 , our matching contributions to the 401(k) plan were approximately $7.1 million, $7.7 million and $10.1 million, respectively. 2017 Retirement of Treasury Stock During the year ended December 31, 2017, we retired 5.0 million shares of existing treasury stock, with a carrying value of $46.6 million , acquired principally through the delivery by our employees of shares to satisfy tax withholding requirements related to the vesting of restricted shares, as well as shares acquired through our stock repurchase program. These retired shares are now included in the pool of authorized but unissued shares. Our accounting policy upon the retirement of treasury stock is to deduct its par value from common stock and reduce additional paid-in capital by the excess amount of treasury stock retired. |
Stock Compensation
Stock Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock Compensation | Note 8. Stock Compensation The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of May 24, 2017 (the “2004 Plan”), is an incentive plan that provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, SARs settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 48.4 million shares of common stock have been authorized for issuance pursuant to the 2004 Plan. As of December 31, 2017 , 13.2 million shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance-based awards. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors. The 2004 Plan was last approved by our stockholders in May 2017 and will expire in May 2027. Stock-based compensation expense associated with our field employees is included in “Lease operating expenses,” while such expense associated with non-field employees is included in “General and administrative expenses” in the Consolidated Statements of Operations. Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets. Effective January 1, 2016, with the adoption of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting , we made an accounting policy election to account for forfeitures as they occur, versus the previously-estimated forfeiture rate. Stock-based compensation costs for the years ended December 31, 2017 , 2016 and 2015 , are as follows: Year Ended December 31, In thousands 2017 2016 2015 Stock-based compensation expensed General and administrative expenses $ 15,154 $ 14,359 $ 27,995 Lease operating expenses — 636 2,609 Total stock-based compensation expensed 15,154 14,995 30,604 Stock-based compensation capitalized 4,567 6,047 8,681 Total cost of stock-based compensation arrangements $ 19,721 $ 21,042 $ 39,285 Income tax benefit recognized for stock-based compensation arrangements $ 5,759 $ 5,698 $ 11,630 SARs Prior to January 1, 2016, we granted SARs settled in stock to our employees. The SARs generally become exercisable over a three -year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors. The SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee. The SARs were granted with a strike price equal to the fair market value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant. The following is a summary of our SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2016 5,940,744 $ 13.57 Granted — — Exercised — — Forfeited (193,874 ) 7.35 Expired (2,080,845 ) 15.04 Outstanding at December 31, 2017 3,666,025 13.07 2.6 $ — Exercisable at end of period 3,053,868 $ 14.19 2.3 $ — The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested: Year Ended December 31, In thousands 2017 2016 2015 Intrinsic value of SARs exercised $ — $ — $ 60 Grant-date fair value of SARs vested 1,818 4,787 6,534 As of December 31, 2017 , there was $34 thousand of total compensation cost to be recognized in future periods related to nonvested share-based SAR compensation arrangements. The cost is expected to be recognized over a weighted-average period of 0.2 years . There were no tax benefits realized from the exercises of SARs for the years ended December 31, 2017, 2016 or 2015. Restricted Stock We grant non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Beginning in 2014, non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. Non-performance-based restricted stock vests over a three -year vesting period, with the specific terms of vesting determined at the time of grant. As of December 31, 2017 , there was $15.5 million of unrecognized compensation expense related to nonvested non-performance-based restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.0 years . The following is a summary of the total vesting date fair value of non-performance-based restricted stock: Year Ended December 31, In thousands 2017 2016 2015 Fair value of restricted stock vested $ 9,325 $ 6,161 $ 12,549 A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during the year ended December 31, 2017 , is presented below: Number Weighted Nonvested at December 31, 2016 9,740,785 $ 4.34 Granted 5,714,005 1.56 Vested (4,687,921 ) 4.90 Forfeited (1,018,186 ) 3.70 Nonvested at December 31, 2017 9,748,683 2.51 Performance-Based Equity Awards Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s officers. Performance-based awards generally vest over 1.25 to 3.25 years, and the number of performance-based shares earned (and eligible to vest) during the performance period will depend upon: (1) our level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group (“Performance-Based TSR Awards”). Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the target number of shares will be earned if the maximum target levels are met (200% of target vesting levels). With respect to the 2016 and 2017 performance-based equity awards, any amounts earned above the 100% target levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. If performance is below the designated minimum levels, no performance-based shares will be earned. Performance-Based Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued using a Monte Carlo simulation. During 2017 and 2016 , we granted performance-based equity awards to our officers. As of December 31, 2017, there was $1.8 million of unrecognized compensation expense related to nonvested performance-based equity awards. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.7 years . The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) are as follows: Year Ended December 31, 2017 2016 2015 Weighted average fair value of Performance-Based TSR Awards granted $ 3.42 $ 1.78 $ 7.59 Risk-free interest rate 1.49 % 1.31 % 0.96 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 94.7 % 57.2 % 33.6 % Dividend yield — % — % 3.42 % A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2017 , is as follows: Performance-Based Operational Awards Performance-Based TSR Awards Number Weighted Number Weighted Nonvested at December 31, 2016 964,435 $ 8.00 2,016,423 $ 5.25 Granted (1) 299,258 3.80 769,838 3.42 Vested (2) (653,613 ) 4.61 (165,753 ) 19.81 Forfeited (55,862 ) 5.24 (123,091 ) 4.45 Nonvested at December 31, 2017 554,218 10.01 2,497,417 3.76 (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200% , with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. (2) During 2017, the service period lapsed on these performance unit awards. The lapsed units earned a weighted average of 64% and 53% of target for each vested Operational and TSR performance-based award, respectively, representing 506,035 aggregate shares of common stock issued. The following is a summary of the total vesting date fair value of performance-based equity awards: Year Ended December 31, In thousands 2017 2016 2015 Vesting date fair value of Performance-Based Operational Awards $ 1,079 $ — $ 2,861 Vesting date fair value of Performance-Based TSR Awards 227 81 300 |
Commodity Derivative Contracts
Commodity Derivative Contracts | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivative Contracts | Note 9. Commodity Derivative Contracts We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “ Commodity derivatives expense (income) ” in our Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2017 , all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements. The following table summarizes our commodity derivative contracts as of December 31, 2017 , none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2018 Fixed-Price Swaps Jan – Dec NYMEX 20,500 $ 50.00 – 56.65 $ 51.69 $ — $ — $ — Jan – Dec Argus LLS 5,000 60.10 – 60.25 60.18 — — — 2018 Three-Way Collars (2) Jan – Dec NYMEX 15,000 $ 45.00 – 56.60 $ — $ 36.50 $ 46.50 $ 53.88 2018 Basis Swaps (3) Jan – June Argus WTI 20,000 $ 3.13 – 4.63 $ 4.17 $ — $ — $ — (1) Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes. (3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 10. Fair Value Measurements The FASC Fair Value Measurement topic defines fair value 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 (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps and basis swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of December 31, 2017 , we had no Level 3 recurring fair value measurements. Previous instruments in this category included non-exchange-traded costless collars and three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 : Fair Value Measurements Using: Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2017 Liabilities Oil derivative contracts – current $ — $ (99,061 ) $ — $ (99,061 ) Total Liabilities $ — $ (99,061 ) $ — $ (99,061 ) December 31, 2016 Liabilities Oil derivative contracts – current $ — $ (68,753 ) $ (526 ) $ (69,279 ) Total Liabilities $ — $ (68,753 ) $ (526 ) $ (69,279 ) Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “ Commodity derivatives expense (income) ” in the accompanying Consolidated Statements of Operations. Level 3 Fair Value Measurements The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2017 and 2016 : Year Ended December 31, In thousands 2017 2016 Fair value of Level 3 instruments, beginning of year $ (526 ) $ 52,834 Fair value adjustments on commodity derivatives 526 (2,135 ) Receipt on settlements of commodity derivatives — (51,225 ) Fair value of Level 3 instruments, end of year $ — $ (526 ) The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date $ — $ (526 ) Other Fair Value Measurements The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes, senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of December 31, 2017 and 2016 , excluding pipeline financing and capital lease obligations, was $2,260.6 million and $2,327.8 million , respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 11. Commitments and Contingencies Leases We lease office space, equipment and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have terms up to 8 years . We have subleased part of the office space included in our operating leases for which we received rental payments. The following table summarizes operating lease payments paid and sublease rentals received during the periods indicated: Year Ended December 31, In thousands 2017 2016 2015 Operating lease payments $ 25,075 $ 22,744 $ 29,403 Sublease rental receipts 4,275 3,074 3,698 The following tables summarize by year the remaining non-cancelable future payments under our leases as of December 31, 2017 : In thousands Pipeline 2018 $ 43,105 2019 40,215 2020 27,872 2021 26,092 2022 27,827 Thereafter 137,342 Total minimum lease payments 302,453 Less: Amount representing interest (83,726 ) Present value of minimum lease payments $ 218,727 In thousands Operating 2018 $ 11,315 2019 10,675 2020 9,787 2021 10,020 2022 10,255 Thereafter 28,799 Total minimum lease payments $ 80,851 In addition, we expect to receive approximately $3.5 million for 2018 through 2019 under our sublease agreements. Commitments We have entered into long-term commitments to purchase CO 2 that are either non-cancelable or cancelable only upon the occurrence of specified future events. The commitments continue for up to 15 years . The price we will pay for CO 2 generally varies depending on the amount of CO 2 delivered and the price of oil. Once all commitments have commenced, our annual commitment under these contracts could range from $14 million to $33 million per year, assuming a $60 per Bbl NYMEX oil price. The Company has a CO 2 offtake agreement with Mississippi Power Company (“MSPC”), providing for our purchase of CO 2 generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO 2 from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO 2 from this facility for the foreseeable future. We are party to long-term contracts that require us to deliver CO 2 to our industrial CO 2 customers at various contracted prices, plus we have a CO 2 delivery obligation to Genesis related to one CO 2 volumetric production payment (“VPP”). Based upon the maximum amounts deliverable as stated in the industrial contracts and the VPP, we estimate that we may be obligated to deliver up to 633 Bcf of CO 2 to these customers over the next 15 years . The maximum volume required in any given year is approximately 176 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO 2 reserves at December 31, 2017 , our current production capabilities and our projected levels of CO 2 usage for our own tertiary flooding program. Litigation We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated. Riley Ridge Helium Supply Contract Claim As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20 -year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC. The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium under the helium supply contract. APMTG Helium, LLC filed a case in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, claiming multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. In response, we are taking the position that our contractual obligations are excused by virtue of events that fall within the force majeure provisions in the helium supply contract. The evidentiary phase of the trial closed on November 29, 2017. The parties submitted written closing briefs to the District Court on February 23, 2018 and have agreed to submit written rebuttals to such closing briefs by March 30, 2018. Following those submissions, the case will be fully submitted for determination by the District Court. We currently expect a ruling to be made in the second or third quarter of 2018. The Company plans to continue to vigorously defend its position, but we are unable to predict at this time the outcome of this dispute. Other Contingencies We are subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes. We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Cash Flow, Supplemental Disclosure | Note 12. Supplemental Cash Flow Information Supplemental Cash Flow Information Year Ended December 31, In thousands 2017 2016 2015 Supplemental cash flow information Cash paid for interest, expensed $ 98,261 $ 130,843 $ 146,560 Cash paid for interest, capitalized 30,762 25,982 32,146 Cash paid for interest, treated as a reduction of debt 50,349 25,835 — Cash paid for income taxes 450 375 6,340 Cash received from income tax refunds (13,323 ) (2,455 ) (50,163 ) Noncash investing and financing activities Increase in asset retirement obligations 9,565 11,621 14,866 Increase (decrease) in liabilities for capital expenditures 3,930 (13,593 ) (97,278 ) Retirement of treasury stock 46,562 — 884,129 |
Significant Accounting Polici23
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Organization and Nature of Operations | Organization and Nature of Operations Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations. |
Principles of Reporting and Consolidation | Principles of Reporting and Consolidation The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated. |
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 amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO 2 reserves used to compute depletion of CO 2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; and (8) estimates made in the calculation of income taxes. While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity. |
Cash Equivalents | Cash Equivalents We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $21.4 million , $21.0 million and $17.9 million during the years ended December 31, 2017, 2016 and 2015, respectively, whereby these costs were transferred to the full cost amortization base. Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves declined throughout 2015 and 2016 and led to our recognizing full cost pool ceiling test write-downs totaling $810.9 million and $4.9 billion during 2016 and 2015, respectively. We did not record any ceiling test write-down during 2017. Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables. Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion. |
Property, Plant, and Equipment Policy | CO 2 Properties We own and produce CO 2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO 2 to third parties when it is produced and sold. Expenses related to the production of CO 2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO 2 discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO 2 (see Tertiary Injection Costs above for further discussion). Costs incurred to search for CO 2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO 2 properties” on our Consolidated Balance Sheets. Capitalized CO 2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. Pipelines and Plants CO 2 used in our tertiary floods is transported to our fields through CO 2 pipelines. Costs of CO 2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years . Capitalized costs include $101.1 million of CO 2 pipelines as of December 31, 2017, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2017. Pipelines and plants also include capitalized costs associated with the Riley Ridge gas processing facility in southwestern Wyoming. During the fourth quarter of 2016, we reassessed the estimated useful life of the gas processing facility and related assets, due to the extended shut-in status of the Riley Ridge gas processing facility and our analysis of cost estimates and engineering options to remedy certain existing issues, and recorded accelerated depreciation to fully depreciate capitalized costs related to the facility and intangible assets assigned to helium production rights at Riley Ridge. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years , and computer equipment and software are generally depreciated over a useful life of three to five years . Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term. Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the lease term. Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred. |
Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets Goodwill previously recorded on our Consolidated Balance Sheets represented the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of businesses. Goodwill was not amortized; rather, it was tested for impairment annually during the fourth quarter or when events or changes in circumstances indicated that it was more likely than not the fair value of a reporting unit with goodwill was reduced below its carrying value. Because the fair value of the reporting unit (enterprise value) did not exceed the fair value of assets and liabilities, we recorded a goodwill impairment charge of $1.3 billion during 2015 to fully impair the carrying value of our goodwill. Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming and is included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO 2 contract intangible asset on a straight-line basis over the contract term. Total amortization expense for our intangible assets was $2.4 million and $2.3 million during the years ended December 31, 2017 and 2016 . The following table summarizes the carrying value of our intangible assets as of December 31, 2017 and 2016 : December 31, In thousands 2017 2016 Intangible asset value $ 37,848 $ 37,848 Accumulated amortization (10,645 ) (8,215 ) Net book value $ 27,203 $ 29,633 As of December 31, 2017 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2018 $ 2,430 2019 2,430 2020 2,430 2021 2,430 2022 2,430 |
Impairment Assessment of Long-Lived Assets | Impairment Assessment of Long-Lived Assets The portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2017. |
Asset Retirement Obligations | Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO 2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant. Asset retirement obligations are estimated at the present value of expected future net cash flows. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic. |
Commodity Derivative Contracts | Commodity Derivative Contracts We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change. We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “ Commodity derivatives expense (income) ” in our Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2017 , all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements. |
Concentrations of Credit Risk | Concentrations of Credit Risk Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). There are no margin requirements with the counterparties of our derivative contracts. Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any purchaser to have a material adverse effect upon our operations. For the years ended December 31, 2017 , 2016 and 2015 , two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP ( 22% , 20% and 15% in 2017 , 2016 and 2015 , respectively) and Marathon Petroleum Company ( 10% , 14% and 28% in 2017 , 2016 and 2015 , respectively). |
Revenue Recognition | Revenue Recognition Revenue Recognition. Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivable. We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2017 and 2016 , our aggregate oil and natural gas imbalances were not material to our consolidated financial statements. We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date. |
Income Taxes | Income Taxes Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. |
Net Income (Loss) Per Common Share | Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, stock options, stock appreciation rights (“SARs”), nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible. The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Year Ended December 31, In thousands 2017 2016 2015 Numerator Net income (loss) – basic $ 163,152 $ (976,177 ) $ (4,385,448 ) Effect of potentially dilutive securities Interest on convertible senior notes 49 — — Net income (loss) – diluted $ 163,201 $ (976,177 ) $ (4,385,448 ) Denominator Weighted average common shares outstanding – basic 390,928 373,859 348,802 Effect of potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards 2,242 — — Convertible senior notes 2,751 — — Weighted average common shares outstanding – diluted 395,921 373,859 348,802 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the year ended December 31, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of the period. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2017 2016 2015 Stock options and SARs 4,512 6,427 9,619 Restricted stock and performance-based equity awards 5,645 5,816 3,867 |
Environmental and Litigation Contingencies | Environmental and Litigation Contingencies The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors. Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale , for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows. Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have on our consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We expect to adopt this standard using the modified retrospective method upon its effective date. Management has substantially completed the evaluation of our various revenue contracts. Based on the work performed to date, we do not believe the standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures. |
Fair Value Measurements and Disclosures | The FASC Fair Value Measurement topic defines fair value 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 (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps and basis swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of December 31, 2017 , we had no Level 3 recurring fair value measurements. Previous instruments in this category included non-exchange-traded costless collars and three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. |
Stock Compensation Policy | Stock-based compensation expense associated with our field employees is included in “Lease operating expenses,” while such expense associated with non-field employees is included in “General and administrative expenses” in the Consolidated Statements of Operations. Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets. Restricted Stock We grant non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Beginning in 2014, non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. Non-performance-based restricted stock vests over a three -year vesting period, with the specific terms of vesting determined at the time of grant. SARs Prior to January 1, 2016, we granted SARs settled in stock to our employees. The SARs generally become exercisable over a three -year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors. The SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee. The SARs were granted with a strike price equal to the fair market value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant. Performance-Based Equity Awards Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s officers. Performance-based awards generally vest over 1.25 to 3.25 years, and the number of performance-based shares earned (and eligible to vest) during the performance period will depend upon: (1) our level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group (“Performance-Based TSR Awards”). Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the target number of shares will be earned if the maximum target levels are met (200% of target vesting levels). With respect to the 2016 and 2017 performance-based equity awards, any amounts earned above the 100% target levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. If performance is below the designated minimum levels, no performance-based shares will be earned. Performance-Based Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued using a Monte Carlo simulation. |
Significant Accounting Polici24
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Finite-Lived Intangible Assets | The following table summarizes the carrying value of our intangible assets as of December 31, 2017 and 2016 : December 31, In thousands 2017 2016 Intangible asset value $ 37,848 $ 37,848 Accumulated amortization (10,645 ) (8,215 ) Net book value $ 27,203 $ 29,633 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense | As of December 31, 2017 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2018 $ 2,430 2019 2,430 2020 2,430 2021 2,430 2022 2,430 |
Schedule of Earnings Per Share, Basic and Diluted Reconciliation | The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Year Ended December 31, In thousands 2017 2016 2015 Numerator Net income (loss) – basic $ 163,152 $ (976,177 ) $ (4,385,448 ) Effect of potentially dilutive securities Interest on convertible senior notes 49 — — Net income (loss) – diluted $ 163,201 $ (976,177 ) $ (4,385,448 ) Denominator Weighted average common shares outstanding – basic 390,928 373,859 348,802 Effect of potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards 2,242 — — Convertible senior notes 2,751 — — Weighted average common shares outstanding – diluted 395,921 373,859 348,802 |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2017 2016 2015 Stock options and SARs 4,512 6,427 9,619 Restricted stock and performance-based equity awards 5,645 5,816 3,867 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Changes In Asset Retirement Obligations | The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2017 and 2016 : Year Ended December 31, In thousands 2017 2016 Beginning asset retirement obligations $ 149,120 $ 145,696 Liabilities incurred and assumed during period 2,698 5,383 Revisions in estimated retirement obligations 6,867 6,238 Liabilities settled and sold during period (5,617 ) (19,878 ) Accretion expense 13,242 11,681 Ending asset retirement obligations 166,310 149,120 Less: current asset retirement obligations (1) (554 ) (2,313 ) Long-term asset retirement obligations $ 165,756 $ 146,807 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Summary of unevaluated properties excluded from oil and natural gas properties being amortized | A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2017 , and the year in which the costs were incurred follows: December 31, 2017 Costs Incurred During: In thousands 2017 2016 2015 2014 and Prior Total Property acquisition costs $ 8,527 $ — $ — $ 583,418 $ 591,945 Exploration and development 6,948 20,675 24,470 165,419 217,512 Capitalized interest 30,762 25,220 28,303 57,655 141,940 Total $ 46,237 $ 45,895 $ 52,773 $ 806,492 $ 951,397 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Components of Long-Term Debt | The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2017 and 2016 , and does not reflect transactions in the January 2018 exchange of $174.3 million of our existing senior subordinated notes for an aggregate $133.5 million of additional 9¼% Senior Secured Second Lien Notes due 2022 and new 5% Convertible Senior Notes due 2023 (see December 2017 and January 2018 Note Exchanges below): December 31, In thousands 2017 2016 Senior Secured Bank Credit Agreement $ 475,000 $ 301,000 9% Senior Secured Second Lien Notes due 2021 614,919 614,919 9¼% Senior Secured Second Lien Notes due 2022 381,568 — 3½% Convertible Senior Notes due 2024 84,650 — 6⅜% Senior Subordinated Notes due 2021 215,144 215,144 5½% Senior Subordinated Notes due 2022 408,882 772,912 4⅝% Senior Subordinated Notes due 2023 376,501 622,297 Other Senior Subordinated Notes, including premium of $0 and $3, respectively — 2,253 Pipeline financings 192,429 202,671 Capital lease obligations 26,298 48,718 Total debt principal balance 2,775,391 2,779,914 Future interest payable (1) 316,818 228,825 Debt issuance costs (7,935 ) (15,641 ) Total debt, net of debt issuance costs 3,084,274 2,993,098 Less: current maturities of long-term debt (1) (105,188 ) (83,366 ) Long-term debt and capital lease obligations $ 2,979,086 $ 2,909,732 (1) Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors . Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. |
Indebtedness repayable over the next five years and thereafter | Indebtedness Repayment Schedule At December 31, 2017 , our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows: In thousands 2018 $ 29,841 2019 502,570 2020 16,283 2021 845,540 2022 808,733 Thereafter 572,424 Total indebtedness $ 2,775,391 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Provision (Benefit) | Our income tax provision (benefit) is as follows: Year Ended December 31, In thousands 2017 2016 2015 Current income tax expense (benefit) Federal $ (19,485 ) $ — $ (8,515 ) State (1,388 ) (785 ) 160 Total current income tax benefit (20,873 ) (785 ) (8,355 ) Deferred income tax expense (benefit) Federal (113,863 ) (521,519 ) (1,853,517 ) State 18,084 (21,866 ) (78,662 ) Total deferred income tax benefit (95,779 ) (543,385 ) (1,932,179 ) Total income tax benefit $ (116,652 ) $ (544,170 ) $ (1,940,534 ) |
Deferred Tax Assets And Liabilities | Significant components of our deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows: December 31, In thousands 2017 2016 Deferred tax assets Loss carryforwards – federal $ 18,581 $ 27,078 Loss carryforwards – state 51,510 42,625 Tax credit carryover 20,270 41,132 Business credit carryforwards 74,914 72,748 Derivative contracts 23,024 27,261 Stock-based compensation 2,873 13,887 Unrecognized gain and original issue discount on debt exchange 85,951 108,659 Other 29,481 44,422 Valuation allowance (51,134 ) (36,510 ) Total deferred tax assets 255,470 341,302 Deferred tax liabilities Property and equipment (450,629 ) (628,359 ) Other (2,940 ) (6,821 ) Total deferred tax liabilities (453,569 ) (635,180 ) Total net deferred tax liability $ (198,099 ) $ (293,878 ) |
Income Tax Provision (Benefit) Continuing Operations Income Tax Reconciliation | Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows: Year Ended December 31, In thousands 2017 2016 2015 Income tax provision (benefit) calculated using the federal statutory income tax rate $ 16,275 $ (532,121 ) $ (2,214,094 ) State income taxes, net of federal income tax benefit 2,764 (25,351 ) (117,624 ) Impairment of goodwill with no related tax basis — — 363,666 Tax shortfall on stock-based compensation deduction 5,567 9,557 — Valuation allowance 5,562 2,910 33,600 Enhanced oil recovery tax credits generated (11,307 ) — — Re-measurement of deferreds related to federal tax rate change (132,224 ) — — Other (3,289 ) 835 (6,082 ) Total income tax benefit $ (116,652 ) $ (544,170 ) $ (1,940,534 ) |
Stock Compensation (Tables)
Stock Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stock Compensation [Line Items] | |
Schedule of stock-based compensation costs | Stock-based compensation costs for the years ended December 31, 2017 , 2016 and 2015 , are as follows: Year Ended December 31, In thousands 2017 2016 2015 Stock-based compensation expensed General and administrative expenses $ 15,154 $ 14,359 $ 27,995 Lease operating expenses — 636 2,609 Total stock-based compensation expensed 15,154 14,995 30,604 Stock-based compensation capitalized 4,567 6,047 8,681 Total cost of stock-based compensation arrangements $ 19,721 $ 21,042 $ 39,285 Income tax benefit recognized for stock-based compensation arrangements $ 5,759 $ 5,698 $ 11,630 |
Summary of SARs activity | The following is a summary of our SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2016 5,940,744 $ 13.57 Granted — — Exercised — — Forfeited (193,874 ) 7.35 Expired (2,080,845 ) 15.04 Outstanding at December 31, 2017 3,666,025 13.07 2.6 $ — Exercisable at end of period 3,053,868 $ 14.19 2.3 $ — |
Disclosure of intrinsic value of stock options exercised and grant-date fair value of awards vested | The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested: Year Ended December 31, In thousands 2017 2016 2015 Intrinsic value of SARs exercised $ — $ — $ 60 Grant-date fair value of SARs vested 1,818 4,787 6,534 |
Restricted Stock [Member] | |
Stock Compensation [Line Items] | |
Summary of the total vesting date fair value of non-performance-based restricted stock and performance-based equity awards | The following is a summary of the total vesting date fair value of non-performance-based restricted stock: Year Ended December 31, In thousands 2017 2016 2015 Fair value of restricted stock vested $ 9,325 $ 6,161 $ 12,549 |
Summary of non-performance-based restricted stock activity | A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during the year ended December 31, 2017 , is presented below: Number Weighted Nonvested at December 31, 2016 9,740,785 $ 4.34 Granted 5,714,005 1.56 Vested (4,687,921 ) 4.90 Forfeited (1,018,186 ) 3.70 Nonvested at December 31, 2017 9,748,683 2.51 |
Performance-based equity awards [Member] | |
Stock Compensation [Line Items] | |
Summary of the total vesting date fair value of non-performance-based restricted stock and performance-based equity awards | The following is a summary of the total vesting date fair value of performance-based equity awards: Year Ended December 31, In thousands 2017 2016 2015 Vesting date fair value of Performance-Based Operational Awards $ 1,079 $ — $ 2,861 Vesting date fair value of Performance-Based TSR Awards 227 81 300 |
Schedule of nonvested performance-based Units Activity | A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2017 , is as follows: Performance-Based Operational Awards Performance-Based TSR Awards Number Weighted Number Weighted Nonvested at December 31, 2016 964,435 $ 8.00 2,016,423 $ 5.25 Granted (1) 299,258 3.80 769,838 3.42 Vested (2) (653,613 ) 4.61 (165,753 ) 19.81 Forfeited (55,862 ) 5.24 (123,091 ) 4.45 Nonvested at December 31, 2017 554,218 10.01 2,497,417 3.76 (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200% , with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. (2) During 2017, the service period lapsed on these performance unit awards. The lapsed units earned a weighted average of 64% and 53% of target for each vested Operational and TSR performance-based award, respectively, representing 506,035 aggregate shares of common stock issued. |
Performance-Based TSR Awards [Member] | |
Stock Compensation [Line Items] | |
Summary of Performance-Based TSR Awards Valuation Assumptions | The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) are as follows: Year Ended December 31, 2017 2016 2015 Weighted average fair value of Performance-Based TSR Awards granted $ 3.42 $ 1.78 $ 7.59 Risk-free interest rate 1.49 % 1.31 % 0.96 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 94.7 % 57.2 % 33.6 % Dividend yield — % — % 3.42 % |
Commodity Derivative Contracts
Commodity Derivative Contracts (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity derivative contracts not classified as hedging instruments | The following table summarizes our commodity derivative contracts as of December 31, 2017 , none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2018 Fixed-Price Swaps Jan – Dec NYMEX 20,500 $ 50.00 – 56.65 $ 51.69 $ — $ — $ — Jan – Dec Argus LLS 5,000 60.10 – 60.25 60.18 — — — 2018 Three-Way Collars (2) Jan – Dec NYMEX 15,000 $ 45.00 – 56.60 $ — $ 36.50 $ 46.50 $ 53.88 2018 Basis Swaps (3) Jan – June Argus WTI 20,000 $ 3.13 – 4.63 $ 4.17 $ — $ — $ — (1) Ranges presented for fixed-price swaps and basis swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes. (3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair value hierarchy of financial assets and liabilities | The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 : Fair Value Measurements Using: Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2017 Liabilities Oil derivative contracts – current $ — $ (99,061 ) $ — $ (99,061 ) Total Liabilities $ — $ (99,061 ) $ — $ (99,061 ) December 31, 2016 Liabilities Oil derivative contracts – current $ — $ (68,753 ) $ (526 ) $ (69,279 ) Total Liabilities $ — $ (68,753 ) $ (526 ) $ (69,279 ) |
Changes in fair value of Level 3 assets and liabilities | The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2017 and 2016 : Year Ended December 31, In thousands 2017 2016 Fair value of Level 3 instruments, beginning of year $ (526 ) $ 52,834 Fair value adjustments on commodity derivatives 526 (2,135 ) Receipt on settlements of commodity derivatives — (51,225 ) Fair value of Level 3 instruments, end of year $ — $ (526 ) The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date $ — $ (526 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Table Text Block [Abstract] | |
Schedule of operating lease payments paid and received | The following table summarizes operating lease payments paid and sublease rentals received during the periods indicated: Year Ended December 31, In thousands 2017 2016 2015 Operating lease payments $ 25,075 $ 22,744 $ 29,403 Sublease rental receipts 4,275 3,074 3,698 |
Schedule of capital long-term commitments which require future minimum rental payments | The following tables summarize by year the remaining non-cancelable future payments under our leases as of December 31, 2017 : In thousands Pipeline 2018 $ 43,105 2019 40,215 2020 27,872 2021 26,092 2022 27,827 Thereafter 137,342 Total minimum lease payments 302,453 Less: Amount representing interest (83,726 ) Present value of minimum lease payments $ 218,727 |
Schedule of operating long-term commitments which require future minimum lease payments | In thousands Operating 2018 $ 11,315 2019 10,675 2020 9,787 2021 10,020 2022 10,255 Thereafter 28,799 Total minimum lease payments $ 80,851 |
Supplemental Cash Flow Inform33
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosure | Supplemental Cash Flow Information Year Ended December 31, In thousands 2017 2016 2015 Supplemental cash flow information Cash paid for interest, expensed $ 98,261 $ 130,843 $ 146,560 Cash paid for interest, capitalized 30,762 25,982 32,146 Cash paid for interest, treated as a reduction of debt 50,349 25,835 — Cash paid for income taxes 450 375 6,340 Cash received from income tax refunds (13,323 ) (2,455 ) (50,163 ) Noncash investing and financing activities Increase in asset retirement obligations 9,565 11,621 14,866 Increase (decrease) in liabilities for capital expenditures 3,930 (13,593 ) (97,278 ) Retirement of treasury stock 46,562 — 884,129 |
Significant Accounting Polici34
Significant Accounting Policies (Intangibles) (Details) - CO2 Purchase Contract - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Finite-Lived Intangible Assets [Line Items] | ||
Intangible asset value | $ 37,848 | $ 37,848 |
Accumulated amortization | (10,645) | (8,215) |
Net book value | $ 27,203 | $ 29,633 |
Significant Accounting Polici35
Significant Accounting Policies (Estimated Amortization Expense for Intangibles) (Details 1) $ in Thousands | Dec. 31, 2017USD ($) |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,018 | $ 2,430 |
2,019 | 2,430 |
2,020 | 2,430 |
2,021 | 2,430 |
2,022 | $ 2,430 |
Significant Accounting Polici36
Significant Accounting Policies (Reconciliation of Weighted Average Shares Table) (Details 2) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Numerator | |||
Net income (loss) - basic | $ 163,152 | $ (976,177) | $ (4,385,448) |
Interest on convertible senior notes | 49 | 0 | 0 |
Net income (loss) - diluted | $ 163,201 | $ (976,177) | $ (4,385,448) |
Denominator | |||
Weighted average common shares outstanding – basic | 390,928 | 373,859 | 348,802 |
Restricted stock, stock options, SARs and performance-based equity awards | 2,242 | 0 | 0 |
Convertible senior notes | 2,751 | 0 | 0 |
Weighted average common shares outstanding – diluted | 395,921 | 373,859 | 348,802 |
Significant Accounting Polici37
Significant Accounting Policies Significant Accounting Policies (Antidilutive Securities) (Details 3) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Stock options and SARS | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 4,512 | 6,427 | 9,619 |
Restricted stock and performance-based equity awards | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 5,645 | 5,816 | 3,867 |
Significant Accounting Polici38
Significant Accounting Policies (Details Textuals) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Significant Accounting Policies [Line Items] | |||
Loans and Leases Receivable, Net Amount | $ 17,000 | ||
Ceiling test write-down | 0 | $ 810,921 | $ 4,939,600 |
Impairments of unevaluated costs | 21,400 | 21,000 | 17,900 |
CO2 pipelines not placed in service | 101,100 | ||
Impairment of goodwill | 0 | 0 | $ 1,261,512 |
Amortization of Intangible Assets | $ 2,400 | $ 2,300 | |
Minimum | Pipelines | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 15 years | ||
Minimum | Vehicles | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 5 years | ||
Minimum | Furniture and Fixtures | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 5 years | ||
Minimum | Computer equipment and software | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 3 years | ||
Maximum | Pipelines | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 50 years | ||
Maximum | Vehicles | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 10 years | ||
Maximum | Furniture and Fixtures | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 10 years | ||
Maximum | Computer equipment and software | |||
Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 5 years |
Significant Accounting Polici39
Significant Accounting Policies (Major Customers) (Details Textuals 1) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Marathon Petroleum Company | |||
Product Information [Line Items] | |||
Revenue from major customer (percentage) | 10.00% | 14.00% | 28.00% |
Plains Marketing LP | |||
Product Information [Line Items] | |||
Revenue from major customer (percentage) | 22.00% | 20.00% | 15.00% |
Asset Acquisition and Assets 40
Asset Acquisition and Assets Held for Sale (Details Textuals) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2017 |
Business Combinations [Abstract] | ||
Non-operated working interest acquired in asset acquisition | 23.00% | |
Costs incurred, acquisition of oil and gas properties | $ 71.5 | |
Land available for sale | $ 33.1 |
Asset Retirement Obligations (R
Asset Retirement Obligations (Rollforward) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | ||
Asset Retirement Obligation Roll Forward [Roll Forward] | |||
Beginning asset retirement obligations | $ 149,120 | $ 145,696 | |
Liabilities incurred and assumed during period | 2,698 | 5,383 | |
Revisions in estimated retirement obligations | 6,867 | 6,238 | |
Liabilities settled and sold during period | (5,617) | (19,878) | |
Accretion expense | 13,242 | 11,681 | |
Ending asset retirement obligations | 166,310 | 149,120 | |
Less: current asset retirement obligations | [1] | (554) | (2,313) |
Long-term asset retirement obligations | $ 165,756 | $ 146,807 | |
[1] | Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details Textuals) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Asset Retirement Obligation Disclosure [Abstract] | ||
Balance in escrow accounts | $ 40.6 | $ 39.3 |
Property and Equipment (Summary
Property and Equipment (Summary of Unevaluated Properties Excluded from Amortization) (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary of unevaluated properties excluded from oil and natural gas properties being amortized | ||||
Property acquisition costs | $ 8,527 | $ 0 | $ 0 | $ 583,418 |
Exploration and development | 6,948 | 20,675 | 24,470 | 165,419 |
Capitalized interest | 30,762 | 25,220 | 28,303 | 57,655 |
Total | 46,237 | 45,895 | $ 52,773 | $ 806,492 |
Property acquisition costs | 591,945 | |||
Exploration and development | 217,512 | |||
Capitalized interest | 141,940 | |||
Total | $ 951,397 | $ 927,819 |
Property and Equipment (Details
Property and Equipment (Details Textuals) | 12 Months Ended |
Dec. 31, 2017 | |
Minimum | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |
Anticipated Timing of Inclusion of Costs in Amortization Calculation | 5 years |
Maximum | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |
Anticipated Timing of Inclusion of Costs in Amortization Calculation | 10 years |
Long-Term Debt (Components of L
Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) | 1 Months Ended | |||||||
Jan. 31, 2018 | Dec. 31, 2017 | May 31, 2016 | Dec. 31, 2016 | Apr. 30, 2014 | Feb. 28, 2013 | Feb. 28, 2011 | ||
Debt Instrument [Line Items] | ||||||||
Senior Secured Bank Credit Agreement | $ 475,000,000 | $ 301,000,000 | ||||||
Senior Secured Second Lien Notes | $ 614,900,000 | |||||||
3 1/2% Convertible Senior Notes due 2024 | 84,650,000 | 0 | ||||||
Pipeline financings | 192,429,000 | 202,671,000 | ||||||
Capital lease obligations | 26,298,000 | 48,718,000 | ||||||
Total debt principal balance | 2,775,391,000 | 2,779,914,000 | ||||||
Future interest payable | 316,818,000 | [1] | 228,825,000 | |||||
Debt issuance costs | (7,935,000) | (15,641,000) | ||||||
Total debt, net of debt issuance costs | 3,084,274,000 | 2,993,098,000 | ||||||
Less: current maturities of long-term debt | (105,188,000) | [1] | (83,366,000) | |||||
Long-term Debt and Capital Lease Obligations | 2,979,086,000 | 2,909,732,000 | ||||||
Debt Instrument, Amount Exchanged | $ 609,800,000 | $ 1,057,800,000 | ||||||
Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Amount Exchanged | $ 174,300,000 | |||||||
3 1/2% Convertible Senior Notes Due 2024 | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.50% | |||||||
Senior Secured and Convertible Senior Notes | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Face value of notes | $ 133,500,000 | |||||||
5% Convertible Senior Notes Due 2023 | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | |||||||
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Subordinated Notes | $ 215,144,000 | 215,144,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.375% | |||||||
Face value of notes | $ 400,000,000 | |||||||
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021 | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Amount Exchanged | $ 11,600,000 | |||||||
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Subordinated Notes | $ 408,882,000 | 772,912,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||||
Debt Instrument, Amount Exchanged | $ 364,000,000 | |||||||
Face value of notes | $ 1,250,000,000 | |||||||
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022 | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Amount Exchanged | 94,200,000 | |||||||
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Subordinated Notes | $ 376,501,000 | 622,297,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.625% | |||||||
Debt Instrument, Amount Exchanged | $ 245,800,000 | |||||||
Face value of notes | $ 1,200,000,000 | |||||||
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023 | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Amount Exchanged | 68,500,000 | |||||||
Senior Subordinated Notes | Other Subordinated Notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Subordinated Notes | 0 | 2,253,000 | ||||||
Including premium of | 0 | 3,000 | ||||||
Secured Debt | 9% Senior Secured Second Lien Notes due 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Secured Second Lien Notes | $ 614,919,000 | 614,919,000 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.00% | |||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior Secured Second Lien Notes | $ 381,568,000 | 0 | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | |||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | Subsequent Event | ||||||||
Debt Instrument [Line Items] | ||||||||
Face value of notes | $ 74,100,000 | |||||||
Future interest payable on senior secured and convertible senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Less: current maturities of long-term debt | $ (75,347,000) | (50,349,000) | ||||||
Long-term Debt and Capital Lease Obligations | $ 241,472,000 | $ 178,476,000 | ||||||
[1] | Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. |
Long-Term Debt (Debt Maturity S
Long-Term Debt (Debt Maturity Schedule) (Details 1) $ in Thousands | Dec. 31, 2017USD ($) |
Indebtedness repayment schedule | |
2,018 | $ 29,841 |
2,019 | 502,570 |
2,020 | 16,283 |
2,021 | 845,540 |
2,022 | 808,733 |
Thereafter | 572,424 |
Total indebtedness | $ 2,775,391 |
Long-Term Debt (Details Textual
Long-Term Debt (Details Textuals) | Apr. 30, 2014USD ($) | Jan. 31, 2018USD ($)D$ / shares | Dec. 31, 2017USD ($)sharesD$ / shares | May 31, 2016USD ($)shares | Feb. 28, 2013USD ($) | Feb. 28, 2011USD ($) | Jan. 31, 2018USD ($) | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | |||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Interest in guarantor subsidiaries | 100.00% | 100.00% | |||||||||||
Debt Instrument, Amount Exchanged | $ 609,800,000 | $ 1,057,800,000 | |||||||||||
Senior Secured Second Lien Notes | 614,900,000 | ||||||||||||
Convertible Debt | 84,650,000 | $ 84,650,000 | $ 0 | ||||||||||
Extinguishment of Debt, Amount | 143,600,000 | $ 442,900,000 | |||||||||||
Future interest on 2022 Senior Secured Notes and 2024 Convertible Senior Notes | 316,818,000 | [1] | 316,818,000 | [1] | 228,825,000 | ||||||||
Gain (loss) on extinguishment of debt | $ 0 | 115,095,000 | $ 0 | ||||||||||
Debt Instrument, Repurchased Face Amount | 181,900,000 | ||||||||||||
Debt Instrument, Repurchase Amount | 76,700,000 | ||||||||||||
Lease period included in long term transportation service agreement | 20 years | ||||||||||||
Unamortized debt issuance costs | $ (13,800,000) | $ (13,800,000) | $ (24,700,000) | ||||||||||
Common stock issued as part of debt exchanges | shares | 402,549,346 | 40,700,000 | 402,549,346 | 402,334,655 | |||||||||
Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | $ 174,300,000 | ||||||||||||
Extinguishment of Debt, Amount | $ 40,800,000 | ||||||||||||
Notes Exchange | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Future interest on 2022 Senior Secured Notes and 2024 Convertible Senior Notes | [1] | $ 138,300,000 | $ 138,300,000 | ||||||||||
Gain (loss) on extinguishment of debt | $ 12,000,000 | ||||||||||||
Interest payable | $ 32,300,000 | $ 32,300,000 | |||||||||||
3 1/2% Convertible Senior Notes Due 2024 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.50% | 3.50% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Volume weighted average stock price for automatic conversion | $ / shares | $ 2.65 | ||||||||||||
Threshold trading days for automatic debt conversion | D | 10 | ||||||||||||
Consecutive trading days threshold for automatic debt conversion | D | 15 | ||||||||||||
3 1/2% Convertible Senior Notes Due 2024 | Conversion Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Share conversion rate per $1,000 principal | 455.56 | ||||||||||||
3 1/2% Convertible Senior Notes Due 2024 | Conversion Period Two | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Share conversion rate per $1,000 principal | 444.44 | ||||||||||||
3 1/2% Convertible Senior Notes Due 2024 | Automatic Conversion Period | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Share conversion rate per $1,000 principal | 444.44 | ||||||||||||
5% Convertible Senior Notes Due 2023 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | 5.00% | |||||||||||
Share conversion rate per $1,000 principal | 281.69 | ||||||||||||
Volume weighted average stock price for automatic conversion | $ / shares | $ 3.55 | ||||||||||||
Threshold trading days for automatic debt conversion | D | 10 | ||||||||||||
Consecutive trading days threshold for automatic debt conversion | D | 15 | ||||||||||||
5% Convertible Senior Notes Due 2023 | Subsequent Event | Board of Directors Conversion Increase Option | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Share conversion rate per $1,000 principal | 393.55 | ||||||||||||
Senior Secured Bank Credit Facility | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Borrowing base | $ 1,050,000,000 | $ 1,050,000,000 | |||||||||||
Lender commitments | 1,050,000,000 | $ 1,050,000,000 | |||||||||||
EBITDAX to Consolidated Interest | 1.25 | ||||||||||||
Current Ratio Requirement | 1 | ||||||||||||
Credit facility, unused capacity - commitment fee percentage | 0.50% | ||||||||||||
Credit facility - weighted average interest rate | 4.50% | 3.00% | |||||||||||
Senior Secured Bank Credit Facility | Letter of Credit | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Borrowing capacity under line of credit facility designated for a specific purpose | 100,000,000 | $ 100,000,000 | |||||||||||
Senior Secured Bank Credit Facility | Swingline Loan | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Borrowing capacity under line of credit facility designated for a specific purpose | 25,000,000 | $ 25,000,000 | |||||||||||
Secured Debt | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Total Debt to EBITDA requirement | 2.5 | ||||||||||||
Secured Debt | 9% Senior Secured Second Lien Notes due 2021 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Senior Secured Second Lien Notes | $ 614,919,000 | $ 614,919,000 | $ 614,919,000 | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.00% | 9.00% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Secured Debt | 9% Senior Secured Second Lien Notes due 2021 | Debt Instrument, Redemption, Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 109.00% | ||||||||||||
Secured Debt | 9% Senior Secured Second Lien Notes due 2021 | Initial Redemption Period With Proceeds From Equity Offering Member | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 109.00% | ||||||||||||
Debt Instrument, Percentage of Principal Amount Available To Be Redeemed | 35.00% | ||||||||||||
Secured Debt | 9% Senior Secured Second Lien Notes due 2021 | Initial Redemption Period with Make-Whole Premium | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 100.00% | ||||||||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Senior Secured Second Lien Notes | $ 381,568,000 | $ 381,568,000 | 0 | ||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | 9.25% | |||||||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Face value of notes | $ 74,100,000 | $ 74,100,000 | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | Debt Instrument, Redemption, Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 109.25% | ||||||||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | Initial Redemption Period With Proceeds From Equity Offering Member | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 109.25% | ||||||||||||
Debt Instrument, Percentage of Principal Amount Available To Be Redeemed | 35.00% | ||||||||||||
Secured Debt | 9 1/4% Senior Secured Second Lien Notes Due 2022 | Initial Redemption Period with Make-Whole Premium | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 100.00% | ||||||||||||
Convertible Debt | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Total Debt to EBITDA requirement | 2.5 | ||||||||||||
Convertible Debt | 5% Convertible Senior Notes Due 2023 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Face value of notes | $ 59,400,000 | $ 59,400,000 | |||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | 5.00% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Senior Subordinated Notes | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Gain (loss) on extinguishment of debt | 103,100,000 | ||||||||||||
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Face value of notes | $ 400,000,000 | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.375% | 6.375% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Debt Instrument, Repurchased Face Amount | 9,800,000 | ||||||||||||
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | $ 11,600,000 | ||||||||||||
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021 | Debt Instrument, Redemption, Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 102.125% | ||||||||||||
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | $ 364,000,000 | ||||||||||||
Face value of notes | $ 1,250,000,000 | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | 5.50% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Total Debt to EBITDA requirement | 2.5 | ||||||||||||
Debt Instrument, Repurchased Face Amount | 66,100,000 | ||||||||||||
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | 94,200,000 | ||||||||||||
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022 | Debt Instrument, Redemption, Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 104.125% | ||||||||||||
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023 | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | $ 245,800,000 | ||||||||||||
Face value of notes | $ 1,200,000,000 | ||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.625% | 4.625% | |||||||||||
Selling Price Of Debt Instrument | 100.00% | ||||||||||||
Total Debt to EBITDA requirement | 2.5 | ||||||||||||
Debt Instrument, Repurchased Face Amount | $ 106,000,000 | ||||||||||||
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023 | Subsequent Event | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Amount Exchanged | $ 68,500,000 | ||||||||||||
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023 | Debt Instrument, Redemption, Period One | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 102.313% | ||||||||||||
Year 2018 | Q1 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 3 | ||||||||||||
Year 2018 | Q2 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Year 2018 | Q3 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Year 2018 | Q4 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Year 2019 | Q1 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Year 2019 | Q2 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Year 2019 | Q3 | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Senior Secured Debt to Consolidated EBITDAX | 2.5 | ||||||||||||
Minimum | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Total shares issued upon conversion | shares | 38,000,000 | ||||||||||||
Maximum | |||||||||||||
Long Term Debt (Textuals) [Abstract] | |||||||||||||
Total shares issued upon conversion | shares | 39,000,000 | ||||||||||||
London Interbank Offered Rate (LIBOR) | Minimum | Senior Secured Bank Credit Facility | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Interest rate margins on Senior Secured Bank Credit Facility | 2.50% | ||||||||||||
London Interbank Offered Rate (LIBOR) | Maximum | Senior Secured Bank Credit Facility | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Interest rate margins on Senior Secured Bank Credit Facility | 3.50% | ||||||||||||
Base Rate | Minimum | Senior Secured Bank Credit Facility | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Interest rate margins on Senior Secured Bank Credit Facility | 1.50% | ||||||||||||
Base Rate | Maximum | Senior Secured Bank Credit Facility | |||||||||||||
Senior Secured Bank Credit Facility [Abstract] | |||||||||||||
Interest rate margins on Senior Secured Bank Credit Facility | 2.50% | ||||||||||||
[1] | Future interest payable represents most of the interest due over the term of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”), which has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of December 31, 2017 include $75.3 million of future interest payable related to these notes that is due within the next twelve months. See December 2017 and January 2018 Note Exchanges below for further discussion. |
Income Taxes (Income Tax Provis
Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current income tax expense (benefit) | |||
Federal | $ (19,485) | $ 0 | $ (8,515) |
State | (1,388) | (785) | 160 |
Total current income tax benefit | (20,873) | (785) | (8,355) |
Deferred income tax expense (benefit) | |||
Federal | (113,863) | (521,519) | (1,853,517) |
State | 18,084 | (21,866) | (78,662) |
Total deferred income tax benefit | (95,779) | (543,385) | (1,932,179) |
Total income tax benefit | $ (116,652) | $ (544,170) | $ (1,940,534) |
Income Taxes (Components of Def
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 1) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax assets | ||
Loss carryforwards - federal | $ 18,581 | $ 27,078 |
Loss carryforwards - state | 51,510 | 42,625 |
Tax credit carryover | 20,270 | 41,132 |
Business credit carryforwards | 74,914 | 72,748 |
Derivative contracts | 23,024 | 27,261 |
Stock-based compensation | 2,873 | 13,887 |
Unrecognized gain and original issue discount on debt exchange | 85,951 | 108,659 |
Other | 29,481 | 44,422 |
Valuation allowance | (51,134) | (36,510) |
Total deferred tax assets | 255,470 | 341,302 |
Deferred tax liabilities | ||
Property and equipment | (450,629) | (628,359) |
Other | (2,940) | (6,821) |
Total deferred tax liabilities | (453,569) | (635,180) |
Total net deferred tax liability | $ (198,099) | $ (293,878) |
Income Taxes (Schedule of Effec
Income Taxes (Schedule of Effective Tax Rate Reconciliation) (Details 2) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Effective Income Tax Rate Reconciliation, Amount | |||
Income tax provision (benefit) calculated using the federal statutory income tax rate | $ 16,275 | $ (532,121) | $ (2,214,094) |
State income taxes, net of federal income tax benefit | 2,764 | (25,351) | (117,624) |
Impairment of goodwill with no related tax basis | 0 | 0 | 363,666 |
Tax shortfall on stock-based compensation deduction | 5,567 | 9,557 | 0 |
Valuation allowance | 5,562 | 2,910 | 33,600 |
Enhanced oil recovery credits generated | (11,307) | 0 | 0 |
Remeasurement of deferreds related to federal tax rate change | (132,224) | 0 | 0 |
Other | (3,289) | 835 | (6,082) |
Total income tax benefit | $ (116,652) | $ (544,170) | $ (1,940,534) |
Income Taxes (Details Textuals)
Income Taxes (Details Textuals) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Valuation Allowance [Line Items] | ||
Loss carryforwards - state | $ 51,510 | $ 42,625 |
Valuation allowance | 51,134 | 36,510 |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 14,600 | |
State tax credits | 1,900 | |
Loss carryforwards - federal | 18,581 | 27,078 |
Enhanced oil recovery credit carryforwards | 51,500 | |
Research and development credits | 21,600 | |
Tax credit carryover | 20,270 | $ 41,132 |
Unrecognized Tax Benefits | 5,400 | |
State of Louisiana [Member] | ||
Valuation Allowance [Line Items] | ||
Valuation allowance | 35,300 | |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | (1,300) | |
State of Mississippi [Member] | ||
Valuation Allowance [Line Items] | ||
Valuation allowance | 6,800 | |
State of Louisiana and Mississippi [Member] | ||
Valuation Allowance [Line Items] | ||
Loss carryforwards - state | 51,100 | |
Increase (Decrease) In Deferred Tax Assets Operating Loss Carryforwards State And Local | $ 9,100 |
Stockholders' Equity (Details T
Stockholders' Equity (Details Textuals 1) - 401(k) Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Contribution Benefit Plans Disclosures [Line Items] | |||
Employer contribution rate | 100.00% | ||
Employer's matching contributions | $ 7.1 | $ 7.7 | $ 10.1 |
Maximum | |||
Defined Contribution Benefit Plans Disclosures [Line Items] | |||
Employee contribution rate | 6.00% |
Stockholders' Equity (Details53
Stockholders' Equity (Details Textuals 2) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Retirement of treasury stock, value | $ 0 | $ 0 | |
Treasury Stock | |||
Retirement of treasury stock, value | $ (46,562) | $ 0 | $ (884,129) |
Retirement of treasury stock, shares | 5,000,000 | 60,000,000 | |
Additional Paid-in Capital | |||
Retirement of treasury stock, value | $ 46,557 | $ 884,069 |
Stock Compensation (Schedule of
Stock Compensation (Schedule of Share-Based Compensation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total stock-based compensation expensed | $ 15,154 | $ 14,995 | $ 30,604 |
Stock-based compensation capitalized | 4,567 | 6,047 | 8,681 |
Total cost of stock-based compensation arrangements | 19,721 | 21,042 | 39,285 |
Income tax benefit recognized for stock-based compensation arrangements | 5,759 | 5,698 | 11,630 |
General and administrative expenses [Member] | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total stock-based compensation expensed | 15,154 | 14,359 | 27,995 |
Lease operating expenses [Member] | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total stock-based compensation expensed | $ 0 | $ 636 | $ 2,609 |
Stock Compensation (Summary of
Stock Compensation (Summary of SARs Activity) (Details 2) $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($)$ / sharesshares | |
Share-based Arrangements with Employees and Nonemployees [Abstract] | |
Number of awards outstanding at December 31, 2016 | shares | 5,940,744 |
Weighted average exercise price, December 31, 2016 | $ / shares | $ 13.57 |
Number of awards, granted | shares | 0 |
Weighted average exercise price, granted | $ / shares | $ 0 |
Number of awards, exercised | shares | 0 |
Weighted average exercise price, exercised | $ / shares | $ 0 |
Number of awards, forfeited | shares | (193,874) |
Weighted average exercise price, forfeited | $ / shares | $ 7.35 |
Number of awards, expired | shares | (2,080,845) |
Weighted average exercise price, expired | $ / shares | $ 15.04 |
Number of awards outstanding at December 31, 2017 | shares | 3,666,025 |
Weighted average exercise price, December 31, 2017 | $ / shares | $ 13.07 |
Weighted average remaining contractual life of outstanding SARs | 2 years 7 months |
Aggregate intrinsic value of SARs outstanding | $ | $ 0 |
Exercisable awards at end of period | shares | 3,053,868 |
Weighted average price, exercisable at end of period | $ / shares | $ 14.19 |
Weighted average remaining contractual life of exercisable SARs | 2 years 4 months |
Aggregate intrinsic value of exercisable SARs | $ | $ 0 |
Stock Compensation (Summary o56
Stock Compensation (Summary of Value of SARs) (Details 3) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||
Intrinsic value of SARs exercised | $ 0 | $ 0 | $ 60 |
Grant-date fair value of SARs vested | $ 1,818 | $ 4,787 | $ 6,534 |
Stock Compensation (Summary o57
Stock Compensation (Summary of Vesting Date Fair Value of Awards - Restricted Stock) (Details 4) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Fair value of restricted stock vested | $ 9,325 | $ 6,161 | $ 12,549 |
Stock Compensation (Summary o58
Stock Compensation (Summary of Restricted Stock) (Details 5) - Restricted Stock [Member] | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Nonvested Restricted Stock Outstanding [Line Items] | |
Nonvested at December 31, 2016 | shares | 9,740,785 |
Weighted average grant-date fair value, December 31, 2016 | $ / shares | $ 4.34 |
Granted | shares | 5,714,005 |
Weighted average grant-date fair value, granted | $ / shares | $ 1.56 |
Vested | shares | (4,687,921) |
Weighted average grant-date fair value, vested | $ / shares | $ 4.90 |
Forfeited | shares | (1,018,186) |
Weighted average grant-date fair value, forfeited | $ / shares | $ 3.70 |
Nonvested at December 31, 2017 | shares | 9,748,683 |
Weighted average grant-date fair value, December 31, 2017 | $ / shares | $ 2.51 |
Stock Compensation (TSR Award A
Stock Compensation (TSR Award Assumptions) (Details 6) - Performance-Based TSR Awards [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average fair value of Performance-Based TSR Awards granted | $ 3.42 | $ 1.78 | $ 7.59 |
Risk-free interest rate | 1.49% | 1.31% | 0.96% |
Expected life | 3 years | 3 years | 3 years |
Expected volatility | 94.70% | 57.20% | 33.60% |
Dividend yield | 0.00% | 0.00% | 3.42% |
Stock Compensation (Summary o60
Stock Compensation (Summary of Performance Based Equity Awards) (Details 7) - $ / shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Performance-Based Operational Awards [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Nonvested at December 31, 2016 | 964,435 | |||
Weighted average grant-date fair value, December 31, 2016 | $ 8 | |||
Granted | [1] | 299,258 | ||
Weighted average grant-date fair value, granted | $ 3.80 | |||
Vested | [2] | (653,613) | ||
Weighted average grant-date fair value, vested | $ 4.61 | |||
Forfeited | (55,862) | |||
Weighted average grant-date fair value, forfeited | $ 5.24 | |||
Nonvested at December 31, 2017 | 554,218 | 964,435 | ||
Weighted average grant-date fair value, December 31, 2017 | $ 10.01 | $ 8 | ||
Payout percentage | 64.00% | |||
Performance-Based TSR Awards [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Nonvested at December 31, 2016 | 2,016,423 | |||
Weighted average grant-date fair value, December 31, 2016 | $ 5.25 | |||
Granted | [1] | 769,838 | ||
Weighted average grant-date fair value, granted | $ 3.42 | $ 1.78 | $ 7.59 | |
Vested | [2] | (165,753) | ||
Weighted average grant-date fair value, vested | $ 19.81 | |||
Forfeited | (123,091) | |||
Weighted average grant-date fair value, forfeited | $ 4.45 | |||
Nonvested at December 31, 2017 | 2,497,417 | 2,016,423 | ||
Weighted average grant-date fair value, December 31, 2017 | $ 3.76 | $ 5.25 | ||
Payout percentage | 53.00% | |||
Performance-Based Equity Awards [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vested | (506,035) | |||
Performance-Based Equity Awards [Member] | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Payout percentage | 0.00% | |||
Performance-Based Equity Awards [Member] | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Payout percentage | 200.00% | |||
[1] | Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. | |||
[2] | During 2017, the service period lapsed on these performance unit awards. The lapsed units earned a weighted average of 64% and 53% of target for each vested Operational and TSR performance-based award, respectively, representing 506,035 aggregate shares of common stock issued. |
Stock Compensation (Summary o61
Stock Compensation (Summary of Vesting Date Fair Value of Awards) (Details 8) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Performance-Based Operational Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting date fair value | $ 1,079 | $ 0 | $ 2,861 |
Performance-Based TSR Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting date fair value | $ 227 | $ 81 | $ 300 |
Stock Compensation (Details Tex
Stock Compensation (Details Textual) - USD ($) shares in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Stock Compensation Plans (Textuals) [Abstract] | |||
Maximum number of common stock shares authorized for issuance under Plan | 48.4 | ||
Shares available for future awards | 13.2 | ||
Tax benefit realized for the exercises of SARs | $ 0 | $ 0 | $ 0 |
Stock Appreciation Rights (SARs) [Member] | |||
Stock Compensation Plans (Textuals) [Abstract] | |||
Award vesting period | 3 years | ||
SARs expiration period | 10 years | ||
Total compensation cost to be recognized in future periods | $ 34,000 | ||
Weighted average period over which remaining cost will be recognized | 2 months | ||
Restricted Stock [Member] | |||
Stock Compensation Plans (Textuals) [Abstract] | |||
Award vesting period | 3 years | ||
Total compensation cost to be recognized in future periods | $ 15,500,000 | ||
Weighted average period over which remaining cost will be recognized | 2 years | ||
Performance-based equity awards [Member] | |||
Stock Compensation Plans (Textuals) [Abstract] | |||
Total compensation cost to be recognized in future periods | $ 1,800,000 | ||
Weighted average period over which remaining cost will be recognized | 1 year 8 months | ||
Performance-based equity awards [Member] | Minimum | |||
Stock Compensation Plans (Textuals) [Abstract] | |||
Award vesting period | 1 year 3 months | ||
Performance-based equity awards [Member] | Maximum | |||
Stock Compensation Plans (Textuals) [Abstract] | |||
Award vesting period | 3 years 3 months |
Commodity Derivative Contract63
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) | Dec. 31, 2017bbl / d$ / Barrel |
Swap | NYMEX [Member] | |
Derivative [Line Items] | |
Volume per day | bbl / d | 20,500 |
Weighted average swap price | 51.69 |
Swap | LLS [Member] | |
Derivative [Line Items] | |
Volume per day | bbl / d | 5,000 |
Weighted average swap price | 60.18 |
Three-way Collar | NYMEX [Member] | |
Derivative [Line Items] | |
Volume per day | bbl / d | 15,000 |
Derivative, Floor Price | 45 |
Derivative, Cap Price | 56.60 |
Weighted average sold put price | 36.50 |
Weighted average floor price | 46.50 |
Weighted average ceiling price | 53.88 |
Q1-Q2 | Basis Swap | LLS [Member] | |
Derivative [Line Items] | |
Volume per day | bbl / d | 20,000 |
Weighted average swap price | 4.17 |
Minimum | Swap | NYMEX [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 50 |
Minimum | Swap | LLS [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 60.10 |
Minimum | Q1-Q2 | Basis Swap | LLS [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 3.13 |
Maximum | Swap | NYMEX [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 56.65 |
Maximum | Swap | LLS [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 60.25 |
Maximum | Q1-Q2 | Basis Swap | LLS [Member] | |
Derivative [Line Items] | |
Derivative, Swap Type, Fixed Price | 4.63 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value Hierarchy) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Oil derivative contracts - current | $ (99,061) | $ (69,279) |
Total Liabilities | (99,061) | (69,279) |
Quoted Prices in Active Markets (Level 1) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Oil derivative contracts - current | 0 | 0 |
Total Liabilities | 0 | 0 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Oil derivative contracts - current | (99,061) | (68,753) |
Total Liabilities | (99,061) | (68,753) |
Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Oil derivative contracts - current | 0 | (526) |
Total Liabilities | $ 0 | $ (526) |
Fair Value Measurements (Level
Fair Value Measurements (Level 3 Fair Value Measurements) (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||
Fair value of Level 3 instruments, beginning of year | $ (526) | $ 52,834 |
Fair value adjustments on commodity derivatives | 526 | (2,135) |
Receipt on settlements of commodity derivatives | 0 | (51,225) |
Fair value of Level 3 instruments, end of year | 0 | (526) |
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date | $ 0 | $ (526) |
Fair Value Measurements (Detail
Fair Value Measurements (Details Textuals) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Disclosures [Abstract] | ||
Debt, Fair Value | $ 2,260.6 | $ 2,327.8 |
Commitments and Contingencies67
Commitments and Contingencies (Summary of Operating Lease Payments Paid and Received (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Operating lease payments | $ 25,075 | $ 22,744 | $ 29,403 |
Sublease rental receipts | $ 4,275 | $ 3,074 | $ 3,698 |
Commitments and Contingencies68
Commitments and Contingencies (Future Non-Cancelable Pipeline and Capital Lease Payments) (Details 1) $ in Thousands | Dec. 31, 2017USD ($) |
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |
Capital Leases in Year 1 | $ 43,105 |
Capital Leases in Year 2 | 40,215 |
Capital Leases in Year 3 | 27,872 |
Capital Leases in Year 4 | 26,092 |
Capital Leases in Year 5 | 27,827 |
Capital Leases, Thereafter | 137,342 |
Capital Leases, Total minimum lease payments | 302,453 |
Capital Leases, Less: Amount representing interest | (83,726) |
Capital Leases, Present value of minimum lease payments | $ 218,727 |
Commitments and Contingencies69
Commitments and Contingencies (Schedule of Future Operating Lease Payments) (Details 2) $ in Thousands | Dec. 31, 2017USD ($) |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |
Operating Leases in Year 1 | $ 11,315 |
Operating Leases in Year 2 | 10,675 |
Operating Leases in Year 3 | 9,787 |
Operating Leases in Year 4 | 10,020 |
Operating Leases in Year 5 | 10,255 |
Operating Leases, Thereafter | 28,799 |
Operating Leases, Total minimum lease payments | $ 80,851 |
Commitments and Contingencies70
Commitments and Contingencies (Leases) (Details Textuals) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Leases, Operating [Abstract] | |
Description of lease terms (in years) | 8 years |
Expected future receipts under sublease agreements | $ 3.5 |
Commitments and Contingencies71
Commitments and Contingencies (Commitments) (Details Textuals 1) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)MMcf / d$ / BarrelMMcf | |
Industrial-source CO2 [Member] | |
Long-term Purchase Commitment [Line Items] | |
Term of Long Term Purchase Commitments | 15 years |
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel | 60 |
Industrial-source CO2 [Member] | Minimum | |
Long-term Purchase Commitment [Line Items] | |
Aggregate purchase obligation of CO2 | $ 14 |
Industrial-source CO2 [Member] | Maximum | |
Long-term Purchase Commitment [Line Items] | |
Aggregate purchase obligation of CO2 | $ 33 |
CO2 Volumetric Production Payments and Industrial CO2 Customers [Member] | |
Long-term Purchase Commitment [Line Items] | |
Significant supply commitment remaining volume committed (MMcf) | MMcf | 633,152 |
Significant supply commitment yearly maximum volume required (MMcf/d) | MMcf / d | 176 |
Term of Long Term Supply Arrangement | 15 years |
Helium Supply Arrangement [Member] | |
Long-term Purchase Commitment [Line Items] | |
Term of Long Term Supply Arrangement | 20 years |
Maximum annual payment in event of shortfall | $ 8 |
Maximum payment in event of shortfall | $ 46 |
Commitments and Contingencies72
Commitments and Contingencies (Details Textuals 2) | Dec. 31, 2017USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Material tax assessments | $ 0 |
Supplemental Cash Flow Inform73
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, expensed | $ 98,261 | $ 130,843 | $ 146,560 |
Cash paid for interest, capitalized | 30,762 | 25,982 | 32,146 |
Cash paid for interest, treated as a reduction of debt | 50,349 | 25,835 | 0 |
Cash paid for income taxes | 450 | 375 | 6,340 |
Cash received from income tax refunds | (13,323) | (2,455) | (50,163) |
Noncash investing and financing activities | |||
Increase in asset retirement obligations | 9,565 | 11,621 | 14,866 |
Increase (decrease) in liabilities for capital expenditures | 3,930 | (13,593) | (97,278) |
Other Significant Noncash Transactions [Line Items] | |||
Retirement of treasury stock | 0 | 0 | |
Treasury Stock | |||
Other Significant Noncash Transactions [Line Items] | |||
Retirement of treasury stock | $ 46,562 | $ 0 | $ 884,129 |