Cover Page
Cover Page - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 18, 2020 | Jun. 30, 2019 | |
Document Information [Line Items] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 001-37419 | ||
Entity Registrant Name | PDC ENERGY, INC. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 95-2636730 | ||
Entity Address, Address Line One | 1775 Sherman Street, | ||
Entity Address, Address Line Two | Suite 3000 | ||
Entity Address, City or Town | Denver | ||
Entity Address, State or Province | CO | ||
Entity Address, Postal Zip Code | 80203 | ||
City Area Code | 303 | ||
Local Phone Number | 860-5800 | ||
Title of 12(b) Security | Common Stock, par value $0.01 per share | ||
Trading Symbol | PDCE | ||
Security Exchange Name | NASDAQ | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Smaller Reporting Company | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 100,121,539 | ||
Entity Public Float | $ 2.3 | ||
Entity Central Index Key | 0000077877 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 963 | $ 1,398 |
Accounts receivable, net | 266,354 | 181,434 |
Fair value of derivatives | 28,078 | 84,492 |
Prepaid expenses and other current assets | 8,635 | 7,136 |
Total current assets | 304,030 | 274,460 |
Properties and equipment, net | 4,095,202 | 4,002,862 |
Assets held-for-sale, net | 0 | 140,705 |
Fair value of derivatives | 3,746 | 93,722 |
Other assets | 45,702 | 32,396 |
Total Assets | 4,448,680 | 4,544,145 |
Current liabilities: | ||
Accounts payable | 98,934 | 181,864 |
Production tax liability | 76,236 | 60,719 |
Fair value of derivatives | 2,921 | 3,364 |
Funds held for distribution | 98,393 | 105,784 |
Accrued interest payable | 14,284 | 14,150 |
Other accrued expenses | 70,462 | 75,133 |
Total current liabilities | 361,230 | 441,014 |
Long-term debt | 1,177,226 | 1,194,876 |
Deferred income taxes | 195,841 | 198,096 |
Asset retirement obligations | 95,051 | 85,312 |
Liabilities held-for-sale | 0 | 4,111 |
Fair value of derivatives | 692 | 1,364 |
Other liabilities | 283,133 | 92,664 |
Total liabilities | 2,113,173 | 2,017,437 |
Shareholders' Equity: | ||
Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 617 | 661 |
Additional paid-in capital | 2,384,309 | 2,519,423 |
Retained earnings (deficit) | (47,945) | 8,727 |
Treasury shares - at cost, 34,922 and 45,220 as of December 31, 2019 and 2018, respectively | (1,474) | (2,103) |
Total stockholders' equity | 2,335,507 | 2,526,708 |
Total Liabilities and Stockholders' Equity | $ 4,448,680 | $ 4,544,145 |
Balance Sheet Parentheticals (P
Balance Sheet Parentheticals (Parentheticals) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Balance Sheet Parentheticals [Abstract] | ||
Common Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Common Stock, Shares Authorized | 150,000,000 | 150,000,000 |
Common Stock, Shares, Issued | 61,652,412 | 66,148,609 |
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Treasury Stock, Shares | 34,922 | 45,220 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||||||||||
Results of Operations, Revenue from Oil and Gas Producing Activities | $ 1,307,275 | $ 1,389,961 | $ 913,084 | ||||||||
Commodity price risk management gain (loss), net | (162,844) | 145,237 | (3,936) | ||||||||
Other income | 11,692 | 13,461 | 12,468 | ||||||||
Total revenues | $ 265,022 | $ 365,943 | $ 390,658 | $ 134,500 | $ 794,811 | $ 280,717 | $ 212,531 | $ 260,600 | 1,156,123 | 1,548,659 | 921,616 |
Costs, expenses and other: | |||||||||||
Lease operating expenses | 142,248 | 130,957 | 89,641 | ||||||||
Production taxes | 80,754 | 90,357 | 60,717 | ||||||||
Transportation, gathering and processing expenses | 46,353 | 37,403 | 33,220 | ||||||||
Exploration, geologic and geophysical expense | 4,054 | 6,204 | 47,334 | ||||||||
Impairment of properties and equipment | 38,536 | 458,397 | 285,887 | ||||||||
Impairment of goodwill | 0 | 0 | 75,121 | ||||||||
General and administrative expense | 161,753 | 170,504 | 120,370 | ||||||||
Depreciation, depletion and amortization | 644,152 | 559,793 | 469,084 | ||||||||
Accretion of asset retirement obligations | 6,117 | 5,075 | 6,306 | ||||||||
(Gain) loss on sale of properties and equipment | 9,734 | 394 | (766) | ||||||||
Provision for uncollectible notes receivable | 0 | 0 | 40,203 | ||||||||
Other expenses | 11,317 | 11,829 | 13,157 | ||||||||
Total costs, expenses and other | 267,713 | 321,562 | 280,623 | 275,120 | 538,626 | 270,593 | 400,770 | 260,924 | 1,145,018 | 1,470,913 | 1,159,868 |
Income (loss) from operations | (2,691) | 44,381 | 110,035 | (140,620) | 256,185 | 10,124 | (188,239) | (324) | 11,105 | 77,746 | (238,252) |
Loss on extinguishment of debt | 0 | 0 | 24,747 | ||||||||
Interest expense | (71,171) | (70,730) | (78,694) | ||||||||
Interest income | 72 | 413 | 2,261 | ||||||||
Income (loss) before income taxes | (20,111) | 26,570 | 91,135 | (157,588) | 238,024 | (7,310) | (205,580) | (17,705) | (59,994) | 7,429 | (339,432) |
Income tax (expense) benefit | 3,322 | (5,406) | 211,928 | ||||||||
Net income (loss) | $ (20,952) | $ 15,908 | $ 68,548 | $ (120,176) | $ 178,853 | $ (3,434) | $ (160,257) | $ (13,139) | $ (56,672) | $ 2,023 | $ (127,504) |
Earnings per share attributable to shareholders: | |||||||||||
Basic | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
Diluted | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
Weighted-average common shares outstanding: | |||||||||||
Basic | 64,032 | 66,059 | 65,837 | ||||||||
Diluted | 64,032 | 66,303 | 65,837 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (56,672) | $ 2,023 | $ (127,504) |
Adjustments to net income (loss) to reconcile to net cash provided by operating activities: | |||
Net change in fair value of unsettled commodity derivatives | 145,246 | (260,775) | 17,260 |
Depreciation, depletion and amortization | 644,152 | 559,793 | 469,084 |
Impairment of properties and equipment | 38,536 | 458,397 | 285,887 |
Impairment of goodwill | 0 | 0 | 75,121 |
Exploratory dry hole costs | 0 | 113 | 41,297 |
Provision for uncollectible notes receivable | 0 | 0 | 40,203 |
Loss on extinguishment of debt | 0 | 0 | 24,747 |
Accretion of asset retirement obligations | 6,117 | 5,075 | 6,306 |
Non-cash stock-based compensation | 23,837 | 21,782 | 19,353 |
(Gain) loss on sale of properties and equipment | 9,734 | 394 | (766) |
Amortization of debt discount and issuance costs | 13,575 | 12,769 | 12,907 |
Deferred income taxes | (2,256) | 6,105 | (203,685) |
Other | 3,155 | 2,763 | 2,265 |
Total adjustments to net income (loss) to reconcile to net cash from operating activities: | 882,096 | 806,416 | 709,573 |
Changes in current assets and liabilities: | |||
Accounts receivable | (88,304) | 12,025 | (60,546) |
Other assets | (11,560) | (81) | 3,364 |
Production tax liability | 22,240 | 35,225 | 31,316 |
Accounts payable and accrued expenses | (29,578) | 16,261 | 31,378 |
Funds held for future distribution | (7,298) | 9,973 | 24,472 |
Asset retirement obligations | (21,511) | (13,341) | (10,176) |
Other liabilities | 168,813 | 20,801 | (4,064) |
Total changes in assets and liabilities | 32,802 | 80,863 | 15,744 |
Net cash from operating activities | 858,226 | 889,302 | 597,813 |
Cash flows from investing activities: | |||
Capital expenditures for development of crude oil and natural gas properties | (855,908) | (946,350) | (737,208) |
Capital expenditures for other properties and equipment | (20,839) | (11,055) | (5,094) |
Acquisition of crude oil and natural gas properties | (13,207) | (180,026) | (15,628) |
Proceeds from sale of properties and equipment | 2,105 | 3,562 | 9,991 |
Proceeds from divestitures | 202,076 | 44,693 | 0 |
Sale of promissory note | 0 | 0 | 40,203 |
Restricted cash | 8,001 | 1,249 | (9,250) |
Sale of short-term investments | 0 | 0 | 49,890 |
Purchase of short-term investments | 0 | 0 | (49,890) |
Net cash from investing activities | (677,772) | (1,087,927) | (716,986) |
Proceeds from revolving credit facility | 1,577,000 | 1,072,500 | 0 |
Repayment of revolving credit facility | (1,605,500) | (1,040,000) | 0 |
Proceeds from issuance of senior notes | 0 | 0 | 592,366 |
Redemption of senior notes | 0 | 0 | (519,375) |
Redemption of convertible notes | (519,375) | ||
Payment of debt issuance costs | (72) | (7,704) | (50) |
Purchase of treasury shares | (4,003) | (5,147) | (6,672) |
Finance Lease, Principal Payments | (1,952) | (1,495) | (1,168) |
Stock Repurchased and Retired During Period, Value | (154,363) | 0 | 0 |
Other | 0 | (55) | (103) |
Net cash from financing activities | (188,890) | 18,099 | 64,998 |
Net change in cash, cash equivalents and restricted cash | (8,436) | (180,526) | (54,175) |
Cash, cash equivalents and restricted cash, beginning of year | 9,399 | 189,925 | 244,100 |
Cash, cash equivalents and restricted cash, end of year | $ 963 | $ 9,399 | $ 189,925 |
Consolidated Statement of Equit
Consolidated Statement of Equity - USD ($) $ in Thousands | Total | Parent [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Treasury Stock [Member] | Treasury Stock, Common [Member] |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract] | |||||||
Shares, Issued | 65,704,568 | (28,763) | |||||
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract] | |||||||
Purchase of treasury shares | (107,357) | ||||||
Issuance of treasury shares | 0 | 83,228 | |||||
Non-employee directors' deferred compensation plan | (3,035) | ||||||
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016 | $ 2,622,754 | $ 657 | $ 2,489,557 | $ 134,208 | $ (1,668) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Purchase of treasury shares | $ 6,672 | (6,672) | (6,672) | ||||
Share-based Compensation expense | (19,353) | 19,353 | 19,351 | ||||
Issuance of treasury shares | 0 | $ 2 | (5,517) | 5,517 | |||
Non-employee directors' deferred compensation plan | (185) | (185) | |||||
Net income (Loss) attributable to shareholders | (127,504) | (127,504) | (127,504) | ||||
Stock Issued During Period, Shares, Issued for Services | 250,512 | ||||||
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017 | 2,507,649 | $ 659 | 2,503,294 | 6,704 | $ (3,008) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Stock Repurchased and Retired During Period, Value | 0 | ||||||
Stockholders' Equity, Other | (97) | (97) | 0 | ||||
Shares, Issued | 65,955,080 | (55,927) | |||||
Purchase of treasury shares | (102,647) | ||||||
Issuance of treasury shares | 0 | 104,068 | |||||
Non-employee directors' deferred compensation plan | 9,286 | ||||||
Purchase of treasury shares | 5,147 | (5,147) | $ (5,147) | ||||
Share-based Compensation expense | (21,782) | 21,782 | 21,780 | ||||
Issuance of treasury shares | 0 | $ 2 | (5,561) | 5,561 | |||
Non-employee directors' deferred compensation plan | 491 | 491 | |||||
Net income (Loss) attributable to shareholders | 2,023 | 2,023 | 2,023 | ||||
Stock Issued During Period, Shares, Issued for Services | 193,529 | ||||||
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2018 | 2,526,708 | $ 661 | 2,519,423 | 8,727 | $ (2,103) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Stock Repurchased and Retired During Period, Value | 0 | ||||||
Stockholders' Equity, Other | 90 | 90 | 0 | ||||
Shares, Issued | 66,148,609 | (45,220) | |||||
Purchase of treasury shares | 106,151 | ||||||
Issuance of treasury shares | 112,646 | ||||||
Purchase of treasury shares | 154,363 | 4,003 | $ 4,003 | ||||
Share-based Compensation expense | (23,837) | 23,837 | 23,835 | ||||
Issuance of treasury shares | $ 2 | (4,505) | $ 4,505 | ||||
Net income (Loss) attributable to shareholders | (56,672) | (56,672) | (56,672) | ||||
Stock Issued During Period, Shares, Issued for Services | 213,745 | ||||||
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2019 | 2,335,507 | $ 617 | 2,384,309 | $ (47,945) | $ (1,474) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Stock Repurchased and Retired During Period, Shares | (4,706,139) | 4,706,139 | |||||
Stock Repurchased and Retired During Period, Value | $ (154,363) | $ (46) | (154,317) | $ 154,363 | |||
Treasury Stock, Shares, Retired | (3,803) | 3,803 | |||||
Treasury Stock, Retired, Cost Method, Amount | $ (127) | $ 127 | |||||
Stock Repurchased During Period, Shares | (4,706,139) | ||||||
Stock Repurchased During Period, Value | $ (154,363) | $ (154,363) | |||||
Shares, Issued | 61,652,412 | (34,922) |
NATURE OF OPERATIONS AND BASIS
NATURE OF OPERATIONS AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2019 | |
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract] | |
Nature of Operations [Text Block] | NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2019 , we owned an interest in approximately 2,649 productive gross wells. The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets. Certain immaterial reclassifications have been made to our prior period balance sheet to conform to the current period presentation. The reclassifications had no impact on previously reported results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. Restricted Cash. At December 31, 2018 , our total cash, cash equivalents and restricted cash of $9.4 million was comprised of $1.4 million of cash and cash equivalents and $8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018 . We did not have any restricted cash at December 31, 2019 . Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Properties and Equipment. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . Total depreciation expense related to other property and equipment was $5.7 million , $8.5 million and $6.6 million in 2019 , 2018 and 2017 , respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018 , our capitalized costs for internal-use software were $25.9 million and $1.4 million , respectively. Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million , $9.2 million and $5.0 million in 2019 , 2018 and 2017 , respectively. Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019 , 2018 and 2017 , the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. Recently Adopted Accounting Standards. In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million , other accrued expenses of $4.6 million and other liabilities of $15.5 million |
Acquisition BUSINESS COMBINATIO
Acquisition BUSINESS COMBINATIONS (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Acquisition [Abstract] | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | ACQUISITION In January 2020, we merged with SRC in a transaction valued at $1.7 billion , inclusive of SRC's net debt. Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the Merger Agreement. We expect to account for the SRC Acquisition under the acquisition method of accounting for business combinations and are currently in the process of determining preliminary estimated acquisition date fair values of identifiable assets acquired and liabilities assumed. During 2019 , we recorded transaction costs related to the SRC Acquisition of $7.3 million , which are included in general and administrative expense. As result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $1.7 billion . As part of the SRC acquisition, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility, which had an outstanding balance of $165.0 million at closing. The indenture governing the SRC Senior Notes has a change of control provision pursuant to which, if a “Change of Control” occurs, the issuer is required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million , plus accrued and unpaid interest of $6.2 million . We funded the repurchase with proceeds from our revolving credit facility. Additionally, in August 2019, effective upon on the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million |
Revenue Recognition Revenue Rec
Revenue Recognition Revenue Recognition (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. The adoption of the New Revenue Standard has not significantly impacted our net income. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2019 , 2018 and 2017 : Year Ended December 31, Revenue by Commodity and Operating Region 2019 2018 2017 (1) (in thousands) Crude oil Wattenberg Field $ 767,760 $ 783,158 $ 529,562 Delaware Basin 252,929 252,107 82,677 Utica Shale (2) — 2,696 12,814 Total $ 1,020,689 $ 1,037,961 $ 625,053 Natural gas Wattenberg Field $ 137,143 $ 130,073 $ 131,792 Delaware Basin 13,877 32,010 21,251 Utica Shale (2) — 1,109 5,216 Total $ 151,020 $ 163,192 $ 158,259 NGLs Wattenberg Field $ 94,347 $ 132,820 $ 104,298 Delaware Basin 41,219 55,148 20,756 Utica Shale (2) — 840 4,718 Total $ 135,566 $ 188,808 $ 129,772 Revenue by Operating Region Wattenberg Field $ 999,250 $ 1,046,051 $ 765,652 Delaware Basin 308,025 339,265 124,684 Utica Shale (2) — 4,645 22,748 Total $ 1,307,275 $ 1,389,961 $ 913,084 (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. |
Disaggregation of Revenue [Table Text Block] | REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. The adoption of the New Revenue Standard has not significantly impacted our net income. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2019 , 2018 and 2017 : Year Ended December 31, Revenue by Commodity and Operating Region 2019 2018 2017 (1) (in thousands) Crude oil Wattenberg Field $ 767,760 $ 783,158 $ 529,562 Delaware Basin 252,929 252,107 82,677 Utica Shale (2) — 2,696 12,814 Total $ 1,020,689 $ 1,037,961 $ 625,053 Natural gas Wattenberg Field $ 137,143 $ 130,073 $ 131,792 Delaware Basin 13,877 32,010 21,251 Utica Shale (2) — 1,109 5,216 Total $ 151,020 $ 163,192 $ 158,259 NGLs Wattenberg Field $ 94,347 $ 132,820 $ 104,298 Delaware Basin 41,219 55,148 20,756 Utica Shale (2) — 840 4,718 Total $ 135,566 $ 188,808 $ 129,772 Revenue by Operating Region Wattenberg Field $ 999,250 $ 1,046,051 $ 765,652 Delaware Basin 308,025 339,265 124,684 Utica Shale (2) — 4,645 22,748 Total $ 1,307,275 $ 1,389,961 $ 913,084 (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. |
FAIR VALUE MEASUREMENTS AND DIS
FAIR VALUE MEASUREMENTS AND DISCLOSURES | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement and Measurement Inputs, Recurring and Nonrecurring [Text Block] | FAIR VALUE OF FINANCIAL INSTRUMENTS Determination of Fair Value Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Derivative Financial Instruments We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and through the review of counterparty statements and other supporting documentation. Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2019 2018 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 22,886 $ 8,938 $ 31,824 $ 118,521 $ 59,693 $ 178,214 Total liabilities (3,089 ) (524 ) (3,613 ) (3,364 ) (1,364 ) (4,728 ) Net asset $ 19,797 $ 8,414 $ 28,211 $ 115,157 $ 58,329 $ 173,486 The following table presents a reconciliation of our Level 3 assets measured at fair value: Year Ended December 31, 2019 2018 2017 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 58,329 $ (9,687 ) $ (9,574 ) Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net (41,749 ) 63,257 6,241 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net (8,166 ) 4,759 (6,354 ) Fair value of Level 3 instruments, net asset (liability) end of period $ 8,414 $ 58,329 $ (9,687 ) Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (22,694 ) $ — $ (866 ) Total $ (22,694 ) $ — $ (866 ) The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. Non-Derivative Financial Assets and Liabilities We utilize fair value on a nonrecurring basis to review our proved crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2019 and 2018 : As of December 31, 2019 2018 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 188.6 94.3 % $ 175.4 87.7 % 2024 Senior Notes 409.2 102.3 % 370.2 92.5 % 2026 Senior Notes 599.4 99.9 % 532.4 88.7 % The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. |
Concentration of Risk
Concentration of Risk | 12 Months Ended |
Dec. 31, 2019 | |
Concentration Risks, Types, No Concentration Percentage [Abstract] | |
Concentration Risk Disclosure [Text Block] | CONCENTRATION OF RISK Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2019 2018 (in thousands) Crude oil, natural gas and NGLs sales $ 149,758 $ 155,756 Joint interest billings 29,510 19,580 Midstream asset divestitures deferred payments 81,702 — Derivative counterparties — 3,937 Other 12,860 6,542 Allowance for doubtful accounts (7,476 ) (4,381 ) Accounts receivable, net $ 266,354 $ 181,434 Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, receivable balances from other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2019 and 2018 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2019 and December 31, 2018 , four and three , respectively, of our customers represented 10 percent or more of our crude oil, natural gas and NGLs accounts receivable balance. Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: Year Ended December 31, Customer 2019 2018 2017 Occidental Marketing, Inc. 20.0 % — % — % DCP Midstream, LP 17.0 % 12.5 % 19.6 % Mercuria Energy Trading, Inc. 16.0 % — % — % United Energy Trading, LLC 11.0 % — % — % Suncor Energy Marketing, Inc. — % — % 16.4 % Derivative Counterparties. We utilize commodity derivative instruments to manage a portion of our exposure to price volatility from producing crude oil, natural gas and NGLs. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2019 . Other Accrued Expenses. The following table presents the components of other accrued expenses: As of December 31, 2019 2018 (in thousands) Employee benefits $ 21,611 $ 25,811 Asset retirement obligations 32,200 25,598 Environmental expenses 2,256 3,038 Operating and finance leases 5,926 1,779 Other 8,469 18,907 Other accrued expenses $ 70,462 $ 75,133 Other Liabilities. The following table presents the components of other liabilities as of: As of December 31, 2019 2018 (in thousands) Production taxes $ 68,020 $ 61,310 Deferred oil gathering credits 20,100 22,710 Deferred midstream gathering credits 175,897 — Operating and finance leases 15,779 2,900 Other 3,337 5,744 Other liabilities $ 283,133 $ 92,664 Deferred Oil Gathering Credits. In January 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment is being amortized over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $2.0 million and $1.4 million for 2019 and 2018 , respectively, are included as a reduction to transportation, gathering and processing expenses. Deferred Midstream Gathering Credits. In May 2019, concurrent with the sale of our Delaware Basin produced water gathering and disposal midstream assets, we entered into an agreement with the purchaser which dedicates all of our water gathering and disposal volumes in the Delaware Basin via pipeline for a term of 15 years . We recorded a long-term deferred credit of $40.5 million attributable to the value of the dedication, which is being amortized using the units-of-production basis. Amortization charges related to this deferred credit totaling $0.9 million for 2019 are included as a reduction to lease operating expenses and capital costs. In May 2019, concurrent with the sale of our Delaware Basin crude oil gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering and transport for crude oil from dedicated acreage within an area of mutual interest for a term of 15 years . We recorded a long-term deferred credit of $28.9 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $0.5 million for 2019 are included as crude oil sales. In June 2019, concurrent with the sale of our Delaware Basin natural gas gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering, processing and transportation of our natural gas from certain dedicated leases for a term of 22 years . We recorded a long-term deferred credit of $110.2 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $2.0 million for 2019 are included as a reduction to transportation, gathering and processing expenses. |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2019 , we had derivative instruments, which were comprised of fixed-price swaps, collars and basis protection swaps, in place for a portion of our anticipated 2020 and 2021 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. As of December 31, 2019 , our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. • Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty; • Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; • Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. As of December 31, 2019 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted- Average Contract Price Fair Value December 31, 2019 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2020 3,600 55.00 71.68 7,160 60.98 27,162 2021 — — — 3,200 55.76 3,054 Total Crude Oil 3,600 10,360 $ 30,216 Natural Gas NYMEX 2020 — — — 4,000 2.30 75 Dominion South 2020 — — — 14 2.54 — Total Natural Gas — 4,014 $ 75 Basis Protection - Natural Gas CIG 2020 — $ — $ — 20,500 $ (0.62 ) $ (2,392 ) Waha 2020 — — — 4,000 (1.40 ) 312 Total Basis Protection - Natural Gas — 24,500 $ (2,080 ) Commodity Derivatives Fair Value $ 28,211 (1) Approximately 28.1 percent of the fair value of our commodity derivative assets and 14.5 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). Subsequent to December 31, 2019 , we entered into commodity derivative positions covering approximately 1,000 MBbls and 2,000 MBbls of crude oil production for 2020 and 2021, respectively. Additionally, we received commodity derivative positions covering approximately 3,900 MBbls of crude oil production for 2020 as a result of the SRC Acquisition. We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. The following table presents the balance sheet location and fair value amounts of our derivative instruments as of December 31, 2019 and 2018 : Fair Value Derivative Instruments: Consolidated Balance Sheet Line Item 2019 2018 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 27,766 $ 84,492 Basis protection derivative contracts Fair value of derivatives 312 — 28,078 84,492 Non-current Commodity derivative contracts Fair value of derivatives 3,746 93,722 Total derivative assets $ 31,824 $ 178,214 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 529 748 Basis protection derivative contracts Fair value of derivatives 2,392 2,616 2,921 3,364 Non-current Commodity derivative contracts Fair value of derivatives 692 1,364 Total derivative liabilities $ 3,613 $ 4,728 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated Statements of Operations Line Item 2019 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (17,598 ) $ (115,538 ) $ 13,324 Net change in fair value of unsettled derivatives (145,246 ) 260,775 (17,260 ) Total commodity price risk management gain (loss), net $ (162,844 ) $ 145,237 $ (3,936 ) Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2019 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 31,824 $ (2,619 ) $ 29,205 Liability derivatives: Derivative instruments, at fair value $ 3,613 $ (2,619 ) $ 994 As of December 31, 2018 Derivative instruments, gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 178,214 $ (3,985 ) $ 174,229 Liability derivatives: Derivative instruments, at fair value $ 4,728 $ (3,985 ) $ 743 |
PROPERTIES AND EQUIPMENT
PROPERTIES AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTIES AND EQUIPMENT The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2019 2018 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 6,241,780 $ 5,452,613 Unproved 403,379 492,594 Total crude oil and natural gas properties 6,645,159 5,945,207 Infrastructure and other 41,888 60,612 Land and buildings 12,312 11,243 Construction in progress 408,428 356,095 Properties and equipment, at cost 7,107,787 6,373,157 Accumulated DD&A (3,012,585 ) (2,370,295 ) Properties and equipment, net $ 4,095,202 $ 4,002,862 Midstream Asset Divestitures. During 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $345.6 million . Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $179.6 million allocated to the acreage dedication agreements. In May 2019, we completed the sale of our produced water gathering and disposal midstream assets in the Delaware Basin for $126.3 million , subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $56.3 million . We recorded a gain on the sale of $25.7 million based on the fair value of the tangible assets sold during 2019 . In May 2019, we also completed the sale of our crude oil gathering midstream assets in the Delaware Basin for $37.3 million , subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $15.2 million . We recorded a loss on the sale of $0.2 million based on the fair value of the tangible assets sold during 2019 . In June 2019, we completed the sale of our natural gas gathering midstream assets in the Delaware Basin for $182.0 million ( $100.0 million of which was paid upon closing with the remaining $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $60.5 million . The $82.0 million receivable is included in accounts receivable at December 31, 2019 . We recorded a gain on the sale of $8.5 million based on the fair value of the tangible assets sold during 2019 . The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations. Acreage Acquisition. In September 2019, we exchanged acreage located in Reeves County, Texas with a third party. As additional consideration for the acreage acquired, we paid $2.7 million in cash and recognized a loss of $45.6 million based on the carrying value of the acreage sold. Classification of Assets and Liabilities as Held-for-Sale. Assets held-for-sale at December 31, 2018 included assets sold in the Midstream Asset Divestitures and certain non-core Delaware Basin crude oil and natural gas properties. The following table presents balance sheet data related to assets and liabilities held-for-sale: December 31, 2018 (in thousands) Assets Properties and equipment, net $ 137,448 Other assets 3,257 Total assets $ 140,705 Liabilities Asset retirement obligation $ 4,111 Total liabilities $ 4,111 During 2019 , we sold certain Delaware Basin crude oil and natural gas properties for net cash proceeds of $33.4 million , which approximated the net book value, resulting in no gain or loss on the sale. Impairment Charges. The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2019 2018 2017 (in thousands) Impairment of proved and unproved properties $ 10,599 $ 458,397 $ 285,465 Amortization of individually insignificant unproved properties — — 422 Impairment of infrastructure and other 27,937 — — Total impairment of properties and equipment $ 38,536 $ 458,397 $ 285,887 During 2019 and 2018 , we recorded impairment charges totaling $10.6 million and $458.4 million , respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. During 2019 , we also recorded impairments of $27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable. Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment: As of December 31, 2019 2018 (in thousands, except for number of wells) Beginning balance $ 12,188 $ 15,448 Additions to capitalized exploratory well costs pending the determination of proved reserves 31,901 35,127 Reclassifications to proved properties (28,011 ) (38,387 ) Ending balance $ 16,078 $ 12,188 Number of wells pending determination at period-end 4 2 During 2019, the two wells classified as exploratory at December 31, 2018 were reclassified as productive and four new wells drilled were classified as exploratory. Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2019 2018 2017 (in thousands) Exploratory dry hole costs $ — $ 113 $ 41,297 Geological and geophysical costs, including seismic purchases 3,017 3,401 3,881 Operating, personnel and other 1,037 2,690 2,156 Total exploration, geologic and geophysical expense $ 4,054 $ 6,204 $ 47,334 Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. |
Goodwill (Notes)
Goodwill (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill [Line Items] | |
Goodwill Disclosure [Text Block] | GOODWILL Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $75.1 million . In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. The quantitative test resulted in a determination that a full impairment charge of $75.1 million |
Leases Operating and Financing
Leases Operating and Financing Leases (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lessee Operating and Financing Leases [Text Block] | LEASES On January 1, 2019, we adopted the New Lease Standard issued by the FASB. We determine if an arrangement is representative of a lease under the New Lease Standard at contract inception. ROU assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years . The vehicle leases include options to renew for up to four years. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. The following table presents the components of lease costs: Lease Costs Year Ended December 31, 2019 (in thousands) Operating lease costs $ 4,917 Finance lease costs: Amortization of ROU assets $ 1,961 Interest on lease liabilities 252 Total finance lease costs $ 2,213 Short-term lease costs 170,064 Total lease costs $ 177,194 Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense on our consolidated statements of operations. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment or recognized as expense. The following table presents the balance sheet classification and other information regarding our leases as of: Leases Consolidated Balance Sheet Line Item December 31, 2019 (in thousands) Operating Leases: Operating lease ROU assets Other assets $ 14,926 Operating lease obligation - short-term Other accrued expense $ 4,159 Operating lease obligation - long-term Other liabilities 12,944 Total operating lease liabilities $ 17,103 Finance Leases: Finance lease ROU assets Properties and equipment, net $ 4,637 Finance lease obligation - short-term Other accrued expense $ 1,767 Finance lease obligation - long-term Other liabilities 2,835 Total finance lease liabilities $ 4,602 Weighted-average remaining lease term (years) Operating leases 4.28 Finance leases 3.17 Weighted-average discount rate Operating leases 5.0 % Finance leases 5.0 % Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2019 consist of the following: Operating Leases Finance Leases Total (in thousands) 2020 $ 4,847 $ 1,949 $ 6,796 2021 4,923 1,423 6,346 2022 5,016 855 5,871 2023 1,559 637 2,196 2024 950 95 1,045 Thereafter 1,698 — 1,698 Total lease payments 18,993 4,959 23,952 Less: Interest and discount (1,890 ) (357 ) (2,247 ) Present value of lease liabilities $ 17,103 $ 4,602 $ 21,705 |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Disclosure [Text Block] | ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: Year Ended December 31, 2019 2018 (in thousands) Beginning balance $ 115,021 $ 87,306 Obligations incurred with development activities 4,605 2,793 Obligations incurred with acquisition 2,882 4,332 Accretion expense 6,117 5,075 Revisions in estimated cash flows 28,991 30,166 Obligations discharged with asset retirements (23,426 ) (14,651 ) Obligations discharged with divestitures (6,939 ) — Balance at December 31 127,251 115,021 Liabilities held-for-sale — (4,111 ) Current portion (32,200 ) (25,598 ) Long-term portion $ 95,051 $ 85,312 Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses. |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2019 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt [Text Block] | LONG-TERM DEBT Long-term debt consisted of the following as of: As of December 31, 2019 2018 (in thousands) Senior Notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (14,763 ) (22,766 ) Unamortized debt issuance costs (1,666 ) (2,640 ) Net of unamortized discount and debt issuance costs 183,571 174,594 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (4,611 ) (5,590 ) Net of unamortized debt issuance costs 395,389 394,410 5.75% Senior Notes due May 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (5,734 ) (6,628 ) Net of unamortized debt issuance costs 594,266 593,372 Total senior notes 1,173,226 1,162,376 Revolving Credit Facility: Revolving credit facility due May 2023 4,000 32,500 Total long-term debt, net of unamortized discount and debt issuance costs $ 1,177,226 $ 1,194,876 Senior Notes 2021 Convertible Notes. In September 2016 , we issued $200 million of 1.125% convertible notes due September 15, 2021 in a public offering. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on March 15 and September 15 . The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. As of December 31, 2019 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes. Based upon the December 31, 2019 stock price of $26.17 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. 2024 Senior Notes. In September 2016 , we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 . Interest is payable semi-annually on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2024 Senior Notes are redeemable after September 15, 2019 at fixed redemption prices, currently 104.594 percent of the principal amount redeemed. 2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026. Interest is payable semi-annually on May 15 and November 15 . Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021 , we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. The 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes. Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes and the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2019 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2026 Senior Notes. Revolving Credit Facility In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion . The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our senior notes. In August 2019, we entered into a First Amendment to the Restated Credit Agreement (the "First Amendment"). The First Amendment primarily provided for certain borrowing in connection with the SRC Acquisition and modified certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion . As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $1.7 billion . As part of the SRC acquisition, we assumed the SRC Senior Notes. The SRC Senior Notes contained a change of control provision pursuant to which, if the consummation of the SRC Acquisition resulted in a “Change of Control” under the indenture governing the SRC Senior Notes, we were required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. See the footnote titled Acquisition for information regarding the redemption of the SRC Senior Notes. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2019 , the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent . Principal payments are generally not required until the revolving credit facility expires in May 2023 , unless the borrowing base falls below the outstanding balance. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2019 , we were in compliance with all the revolving credit facility covenants. As of December 31, 2019 and 2018 , debt issuance costs related to our revolving credit facility were $8.9 million and $11.5 million , respectively, and are included in other assets. As of December 31, 2019 and 2018 , availability under our revolving credit facility was $1.3 billion . As of December 31, 2019 , the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was five percent . |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: Year Ending December 31, Area 2020 2021 2022 2023 Thereafter Total Expiration Natural gas (MMcf) Wattenberg Field 30,608 31,025 31,025 31,025 63,992 187,675 August 31, 2026 Delaware Basin 37,552 28,241 9,125 9,125 66,175 150,218 March 31, 2031 Gas Marketing 7,136 7,056 4,495 — — 18,687 August 31, 2022 Total 75,296 66,322 44,645 40,150 130,167 356,580 Crude oil (MBbls) Wattenberg Field 9,992 16,243 16,243 12,567 37,255 92,300 December 31, 2027 Delaware Basin 8,784 8,030 8,030 8,030 — 32,874 December 31, 2023 Total 18,776 24,273 24,273 20,597 37,255 125,174 Water (MBbls) Wattenberg Field 6,224 6,207 6,207 6,206 6,223 31,067 December 31, 2024 Total 6,224 6,207 6,207 6,206 6,223 31,067 Dollar commitment (in thousands) $ 85,159 $ 106,322 $ 101,107 $ 85,774 $ 202,532 $ 580,894 Wattenberg Field. We have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. We are currently satisfying the volume commitment. Delaware Basin . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels of crude oil per day. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. Crude Oil, Natural Gas and NGLs Sales . For 2019 , amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $50.1 million and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales. In addition, for 2019 and 2018 , $1.9 million and $1.6 million , respectively, related to long-term transportation volumes were recorded in transportation, gathering and processing expense. Amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas of $10.0 million for 2017 were recorded in transportation, gathering and processing expense. In March 2018, we completed the disposition of our Utica Shale properties. Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. Action Regarding Partnerships . In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"), filed in the United States District Court for the District of Colorado (the "District Court"). The original complaint stated that it was a derivative action brought by a number of limited partner investors seeking to assert claims for breach of fiduciary duties on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC. The complaint was subsequently amended to include putative class claims for breach of the partnership agreements. The plaintiffs also included claims against two of our senior officers and three independent members of the Board for allegedly aiding and abetting PDC's purported breach of fiduciary duty. We filed a motion to dismiss on July 31, 2018. On February 19, 2019, the District Court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage to the Partnerships as grounds to support their claims for breach of fiduciary duty against PDC. On June 4, 2019, the District Court entered an order holding its opinion on the motion to dismiss in abeyance pending resolution of the Partnerships' bankruptcy cases and staying the litigation. As discussed in more detail below, the District Court in Colorado has dismissed the Dufresne Case. Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). Prior to the bankruptcy filings, PDC designated a third-party (the “Responsible Party”) to analyze strategic options for the Partnerships. After designation of the Responsible Party and before filing the Chapter 11 Proceedings, PDC and the Partnerships agreed to enter into a transaction pursuant to which PDC would acquire substantially all of the Partnerships’ assets through a Chapter 11 plan of liquidation and obtain a release of claims from the Partnerships, including the claims asserted in the Dufresne Case. In June 2019, the Responsible Party, PDC and the plaintiffs in the Dufresne Case reached a settlement of the matters raised in the Dufresne Case and the Chapter 11 Proceedings. The settlement, which settles all claims asserted against PDC, whether direct or derivative, including, but not limited to, the claims asserted in the Dufresne Case, was incorporated into an Amended Chapter 11 Plan (the “Amended Chapter 11 Plan”). The Disclosure Statement accompanying the Amended Chapter 11 Plan was approved by the Bankruptcy Court in August 2019 along with procedures for soliciting votes on the Amended Chapter 11 Plan. The Amended Chapter 11 Plan was distributed to the Partnership unit holders for voting. On October 2, 2019, the Bankruptcy Court held a hearing to consider confirmation of the Amended Chapter 11 Plan and, on October 3, 2019, entered an order confirming the Amended Chapter 11 Plan. The requirements for the Amended Chapter 11 Plan to become effective were met on October 21, 2019 (the “Effective Date”). As contemplated by the Amended Chapter 11 Plan, on the Effective Date, PDC funded the settlement payment, purchase price for the Partnership’s oil and gas assets and the administrative reserve. Additionally, the Partnership’s oil and gas assets were conveyed to PDC and PDC and the plaintiffs in the Dufresne Case submitted an agreed order dismissing the Dufresne Case with prejudice to the District Court. The District Court entered the agreed order on October 23, 2019, dismissing the Dufresne Case with prejudice. On December 5, 2019, the Bankruptcy Court entered orders approving final fee applications of the debtors' legal representatives and professional service providers, which were paid before the end of 2019, along with distributions of the settlement amount pursuant to the Amended Chapter 11 Plan to the Partnership unit holders. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2019 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses. The liability ultimately incurred with respect to a matter may exceed the related accrual. On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $130,000 , of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. We have completed the corrective actions in a timely manner and some of our reclamation activities are ongoing. In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the COGCC and are working to close this backlog of site reclamation work. We do not believe potential penalties and other expenditures associated with this disclosure will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ( $1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $18 million , primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $1.7 million . Additionally, we are subject to the revised requirements of the COC entered into by SRC with CDPHE as described in "Risk Factors -We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business." We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. We are in the process of implementing the consent decree program, recently expanded to include the COC. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of the Board violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome. Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. |
COMMON STOCK
COMMON STOCK | 12 Months Ended |
Dec. 31, 2019 | |
COMMON STOCK [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block] | COMMON STOCK Stock-Based Compensation Plans 2018 Equity Incentive Plan . In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of the Board (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. We began issuing shares from the 2018 Plan during 2019. As of December 31, 2019 , there were 1,429,004 shares available for grant under the 2018 Plan. 2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may continue to use the 2010 Plan to grant awards. As of December 31, 2019 , there were 133,330 shares available for grant under the 2010 Plan. The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2019 2018 2017 (in thousands) Stock-based compensation expense $ 23,837 $ 21,782 $ 19,353 Income tax benefit (5,780 ) (5,210 ) (7,372 ) Net stock-based compensation expense $ 18,057 $ 16,572 $ 11,981 Restricted Stock Units Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed . The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for 2019 : Shares Weighted-Average Non-vested at December 31, 2018 618,407 $ 54.16 Granted 588,899 40.34 Vested (307,450 ) 52.98 Forfeited (103,930 ) 45.62 Non-vested at December 31, 2019 795,926 45.51 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2019 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 11,652 $ 12,282 $ 16,303 Total intrinsic value of time-based awards non-vested 20,829 18,404 24,334 Market price per share as of December 31, 26.17 29.76 51.54 Weighted-average grant date fair value per share 40.34 50.69 65.14 Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2019 was $21.4 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. Performance Stock Units Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved . The Compensation Committee awarded a total of 139,197 market-based PSUs to our executive officers during 2019 . In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2021, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2019 2018 2017 Expected term of award (in years) 3 3 3 Risk-free interest rate 2.5 % 2.4 % 1.4 % Expected volatility 41.4 % 42.3 % 51.4 % The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. The following table presents the change in non-vested market-based awards during 2019 : Shares Weighted-Average Non-vested at December 31, 2018 102,914 $ 74.88 Granted 139,197 56.68 Vested (20,969 ) 94.02 Forfeited — — Non-vested at December 31, 2019 221,142 61.61 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2019 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 530 $ 620 $ 2,687 Total intrinsic value of market-based awards non-vested 5,787 3,063 2,698 Market price per share as of December 31, 26.17 29.76 51.54 Weighted-average grant date fair value per share 56.68 69.98 94.02 Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2019 was $7.5 million . This cost is expected to be recognized over a weighted-average period of 1.6 years. Stock Appreciation Rights The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The Compensation Committee awarded SARs to our executive officers in 2017 . There were no SARs awarded to our executive officers in 2018 or 2019 . The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: Year Ended December 31, 2017 Expected term of award (in years) 6 Risk-free interest rate 2.0 % Expected volatility 53.3 % Weighted-average grant date fair value per share $ 38.58 The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): Year Ended December 31, 2019 2018 2017 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Outstanding at January 1, 290,258 $ 46.64 4.6 $ 125 298,220 $ 47.39 $ 2,490 244,078 $ 41.36 $ 7,620 Awarded — — — — — — — 54,142 74.57 — Modified — — — — 63,969 42.83 — — — — Expired — — — — (71,931 ) 46.34 — — — — Outstanding at December 31, 290,258 46.64 3.6 41 290,258 46.64 125 298,220 47.39 2,490 Exercisable at December 31, 276,775 45.28 3.4 41 260,101 44.88 125 223,865 43.28 2,267 We expect all SARs outstanding as of December 31, 2019 to vest in 2020. The SARS modified during 2018, as included in the table above, were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2019 is not material and will be recognized within the next twelve months. Preferred stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by the Board from time to time. Through December 31, 2019 , no |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES The table below presents the components of our provision for income tax (expense) benefit for the years presented: Year Ended December 31, 2019 2018 2017 (in thousands) Current: Federal $ 1,366 $ 887 $ 8,443 State (300 ) (188 ) (200 ) Total current income tax benefit 1,066 699 8,243 Deferred: Federal 4,507 (1,986 ) 193,809 State (2,251 ) (4,119 ) 9,876 Total deferred income tax (expense) benefit 2,256 (6,105 ) 203,685 Income tax (expense) benefit $ 3,322 $ (5,406 ) $ 211,928 The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: Year Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % State income tax, net 3.6 (6.4 ) 1.8 Federal tax credits (3.3 ) (52.1 ) — Effect of state income tax rate changes (6.4 ) 6.7 — Change in valuation allowance (0.6 ) 45.5 — Non-deductible compensation (5.0 ) 21.8 (0.3 ) Non-deductible acquisition costs (2.3 ) — — Non-deductible government relations (1.0 ) 31.8 — Other non-deductible items (0.5 ) 4.9 — Federal tax reform rate reduction — — 33.7 Non-deductible goodwill impairment — — (7.7 ) Other — (0.4 ) (0.1 ) Effective tax rate 5.5 % 72.8 % 62.4 % Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 are presented below. As of December 31, 2019 2018 (in thousands) Deferred tax assets: Deferred compensation $ 9,905 $ 9,963 Asset retirement obligations 30,993 27,166 Federal NOL carryforward 22,965 54,736 State NOL and tax credit carryforwards, net 9,508 13,223 Federal tax - credit carryforwards 4,448 7,756 Prepaid revenue 4,874 5,288 Other 3,887 4,647 Valuation allowance (3,775 ) (3,380 ) Total gross deferred tax assets 82,805 119,399 Deferred tax liabilities: Properties and equipment 268,234 270,565 Net change in fair value of unsettled derivatives 6,841 41,496 Convertible debt 3,571 5,434 Total gross deferred tax liabilities 278,646 317,495 Net deferred tax liability $ 195,841 $ 198,096 As of December 31, 2019 , we have prior year federal NOL carryforwards of $175.7 million of which $31.5 million will begin to expire in 2036. Also, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. We expect to utilize $126.4 million of these NOLs to offset current federal taxable income. As of December 31, 2019 , we have state NOL carryforwards of $265.9 million that begin to expire in 2030 and state credit carryforwards of $4.0 million that begin to expire in 2022 . We expect to utilize $98.0 million of these NOLs to offset current state taxable income. Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards. Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2019 . The statutes of limitations for most of our state tax jurisdictions are open for tax year 2015 forward. The IRS partially accepted our 2018 tax return. The 2018 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We continue to voluntarily participate in the IRS CAP Program for the 2019 and 2020 tax years. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. |
Earnings per share
Earnings per share | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | |
Earnings Per Share [Text Block] | EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents our weighted-average basic and diluted shares outstanding: Year Ended December 31, 2019 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 64,032 66,059 65,837 Dilutive effect of: RSUs and PSUs — 173 — Other equity-based awards — 71 — Weighted-average common shares and equivalents outstanding - diluted 64,032 66,303 65,837 For 2019 and 2017 , we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive. The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2019 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 989 145 590 Other equity-based awards 302 109 75 Total anti-dilutive common share equivalents 1,291 254 665 The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During 2019 , 2018 and 2017 , the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation. |
Supplemental Cash Flow Suppleme
Supplemental Cash Flow Supplemental Cash Flow (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Elements [Abstract] | |
Cash Flow, Supplemental Disclosures [Text Block] | SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Year Ended December 31, 2019 2018 (1) 2017 (1) (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 57,439 $ 55,586 $ 69,880 Income taxes (1,167 ) (6,719 ) (13,925 ) Non-cash investing and financing activities: Change in accounts payable related to capital expenditures (68,246 ) 36,328 50,761 Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal 29,533 37,136 839 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5,301 $ — $ — Operating cash flows from finance leases 253 — — Financing cash flows from finance leases 1,952 — — ROU assets obtained in exchange for lease obligations: Operating leases $ 1,428 $ — $ — Finance leases 2,323 — — (1) As we have elected the modified retrospective method of adoption for the New Lease, cash flows related to lease liabilities have not been restated for 2018 and 2017. |
Subsidiary Guarantor SUBSIDIARY
Subsidiary Guarantor SUBSIDIARY GUARANTOR (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
Guarantor Obligations [Line Items] | |
Guarantees [Text Block] | SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for: (i) PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; (ii) PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; (iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and (iv) Parent and subsidiaries on a consolidated basis ("Consolidated"). The Guarantor is 100 percent owned by the Parent. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Consolidating Balance Sheets December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 963 $ — $ — $ 963 Accounts receivable, net 140,742 125,612 — 266,354 Fair value of derivatives 28,078 — — 28,078 Prepaid expenses and other current assets 8,204 431 — 8,635 Total current assets 177,987 126,043 — 304,030 Properties and equipment, net 2,328,337 1,766,865 — 4,095,202 Intercompany receivable 348,818 — (348,818 ) — Investment in subsidiaries 1,286,931 — (1,286,931 ) — Fair value of derivatives 3,746 — — 3,746 Other assets 38,863 6,839 — 45,702 Total Assets $ 4,184,682 $ 1,899,747 $ (1,635,749 ) $ 4,448,680 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 72,212 $ 26,722 $ — $ 98,934 Production tax liability 67,509 8,727 — 76,236 Fair value of derivatives 2,921 — — 2,921 Funds held for distribution 83,072 15,321 — 98,393 Accrued interest payable 14,281 3 — 14,284 Other accrued expenses 68,803 1,659 — 70,462 Total current liabilities 308,798 52,432 — 361,230 Intercompany payable — 348,818 (348,818 ) — Long-term debt 1,177,226 — — 1,177,226 Deferred income taxes 169,520 26,321 — 195,841 Asset retirement obligations 87,749 7,302 — 95,051 Fair value of derivatives 692 — — 692 Other liabilities 105,190 177,943 — 283,133 Total liabilities 1,849,175 612,816 (348,818 ) 2,113,173 Commitments and contingent liabilities Stockholders' equity Common shares 617 — — 617 Additional paid-in capital 2,384,309 1,766,775 (1,766,775 ) 2,384,309 Retained deficit (47,945 ) (479,844 ) 479,844 (47,945 ) Treasury shares (1,474 ) — — (1,474 ) Total stockholders' equity 2,335,507 1,286,931 (1,286,931 ) 2,335,507 Total Liabilities and Stockholders' Equity $ 4,184,682 $ 1,899,747 $ (1,635,749 ) $ 4,448,680 Consolidating Balance Sheets December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 1,398 $ — $ — $ 1,398 Accounts receivable, net 146,529 34,905 — 181,434 Fair value of derivatives 84,492 — — 84,492 Prepaid expenses and other current assets 6,725 411 — 7,136 Total current assets 239,144 35,316 — 274,460 Properties and equipment, net 2,270,711 1,732,151 — 4,002,862 Assets held-for-sale, net — 140,705 — 140,705 Intercompany receivable 451,601 — (451,601 ) — Investment in subsidiaries 1,316,945 — (1,316,945 ) — Fair value of derivatives 93,722 — — 93,722 Other assets 30,084 2,312 — 32,396 Total Assets $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 110,847 $ 71,017 $ — $ 181,864 Production tax liability 53,309 7,410 — 60,719 Fair value of derivatives 3,364 — — 3,364 Funds held for distribution 90,183 15,601 — 105,784 Accrued interest payable 14,143 7 — 14,150 Other accrued expenses 73,689 1,444 — 75,133 Total current liabilities 345,535 95,479 — 441,014 Intercompany payable — 451,601 (451,601 ) — Long-term debt 1,194,876 — — 1,194,876 Deferred income taxes 162,368 35,728 — 198,096 Asset retirement obligations 79,904 5,408 — 85,312 Liabilities held-for-sale — 4,111 — 4,111 Fair value of derivatives 1,364 — — 1,364 Other liabilities 91,452 1,212 — 92,664 Total liabilities 1,875,499 593,539 (451,601 ) 2,017,437 Commitments and contingent liabilities Stockholders' equity Common shares 661 — — 661 Additional paid-in capital 2,519,423 1,766,775 (1,766,775 ) 2,519,423 Retained earnings (deficit) 8,727 (449,830 ) 449,830 8,727 Treasury shares (2,103 ) — — (2,103 ) Total stockholders' equity 2,526,708 1,316,945 (1,316,945 ) 2,526,708 Total Liabilities and Stockholders' Equity $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Consolidating Statements of Operations Year Ended December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 999,250 $ 308,025 $ — $ 1,307,275 Commodity price risk management loss, net (162,844 ) — — (162,844 ) Other income 10,972 720 — 11,692 Total revenues 847,378 308,745 — 1,156,123 Costs, expenses and other Lease operating expenses 94,829 47,419 — 142,248 Production taxes 61,577 19,177 — 80,754 Transportation, gathering and processing expenses 23,719 22,634 — 46,353 Exploration, geologic and geophysical expense 1,111 2,943 — 4,054 General and administrative expense 144,345 17,408 — 161,753 Depreciation, depletion and amortization 451,282 192,870 — 644,152 Accretion of asset retirement obligations 5,446 671 — 6,117 Impairment of properties and equipment 292 38,244 — 38,536 (Gain) loss on sale of properties and equipment (853 ) 10,587 — 9,734 Other expenses 11,317 — — 11,317 Total costs, expenses and other 793,065 351,953 — 1,145,018 Income (loss) from operations 54,313 (43,208 ) — 11,105 Interest expense (75,257 ) 4,086 — (71,171 ) Interest income 71 1 — 72 Loss before income taxes (20,873 ) (39,121 ) — (59,994 ) Income tax (expense) benefit (5,784 ) 9,106 — 3,322 Equity in loss of subsidiary (30,015 ) — 30,015 — Net loss $ (56,672 ) $ (30,015 ) $ 30,015 $ (56,672 ) Consolidating Statements of Operations Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 1,050,696 $ 339,265 $ — $ 1,389,961 Commodity price risk management gain, net 145,237 — — 145,237 Other income 10,744 2,717 — 13,461 Total revenues 1,206,677 341,982 — 1,548,659 Costs, expenses and other Lease operating expenses 92,228 38,729 — 130,957 Production taxes 67,819 22,538 — 90,357 Transportation, gathering and processing expenses 16,607 20,796 — 37,403 Exploration, geologic and geophysical expense 1,234 4,970 — 6,204 General and administrative expense 152,798 17,706 — 170,504 Depreciation, depletion and amortization 389,841 169,952 — 559,793 Accretion of asset retirement obligations 4,617 458 — 5,075 Impairment of properties and equipment 27 458,370 — 458,397 (Gain) loss on sale of properties and equipment (4,387 ) 4,781 — 394 Other expenses 11,829 — — 11,829 Total costs, expenses and other 732,613 738,300 — 1,470,913 Income (loss) from operations 474,064 (396,318 ) — 77,746 Interest expense (73,251 ) 2,521 — (70,730 ) Interest income 413 — — 413 Income (loss) before income taxes 401,226 (393,797 ) — 7,429 Income tax (expense) benefit (98,611 ) 93,205 — (5,406 ) Equity in loss of subsidiary (300,592 ) — 300,592 — Net income (loss) $ 2,023 $ (300,592 ) $ 300,592 $ 2,023 Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. Consolidating Statements of Operations Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 788,400 $ 124,684 $ — $ 913,084 Commodity price risk management loss, net (3,936 ) — — (3,936 ) Other income 11,901 567 — 12,468 Total revenues 796,365 125,251 — 921,616 Costs, expenses and other Lease operating expenses 68,031 21,610 — 89,641 Production taxes 53,236 7,481 — 60,717 Transportation, gathering and processing expenses 23,301 9,919 — 33,220 Exploration, geologic and geophysical expense 1,092 46,242 — 47,334 General and administrative expense 107,518 12,852 — 120,370 Depreciation, depletion and amortization 403,984 65,100 — 469,084 Accretion of asset retirement obligations 5,965 341 — 6,306 Impairment of properties and equipment 4,951 280,936 — 285,887 Impairment of goodwill — 75,121 — 75,121 Gain on sale of properties and equipment (766 ) — — (766 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Other expenses 13,157 — — 13,157 Total costs, expenses and other 640,266 519,602 — 1,159,868 Income (loss) from operations 156,099 (394,351 ) — (238,252 ) Loss on extinguishment of debt (24,747 ) — — (24,747 ) Interest expense (79,919 ) 1,225 — (78,694 ) Interest income 2,261 — — 2,261 Income (loss) before income taxes 53,694 (393,126 ) — (339,432 ) Income tax (expense) benefit (33,643 ) 245,571 — 211,928 Equity in loss of subsidiary (147,555 ) — 147,555 — Net loss $ (127,504 ) $ (147,555 ) $ 147,555 $ (127,504 ) Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill. Consolidating Statements of Cash Flows Year Ended December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 579,464 $ 278,762 $ — $ 858,226 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (485,725 ) (370,183 ) — (855,908 ) Capital expenditures for other properties and equipment (20,361 ) (478 ) — (20,839 ) Acquisition of crude oil and natural gas properties (12,141 ) (1,066 ) — (13,207 ) Proceeds from sale of properties and equipment 399 1,706 — 2,105 Proceeds from divestiture 5,515 196,561 — 202,076 Restricted cash 8,001 — — 8,001 Intercompany transfers 105,004 — (105,004 ) — Net cash from investing activities (399,308 ) (173,460 ) (105,004 ) (677,772 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,577,000 — — 1,577,000 Repayment of revolving credit facility (1,605,500 ) — — (1,605,500 ) Payment of debt issuance costs (72 ) — — (72 ) Purchase of treasury stock (154,363 ) — — (154,363 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (4,003 ) — — (4,003 ) Principal payments under financing lease obligations (1,654 ) (298 ) — (1,952 ) Intercompany transfers — (105,004 ) 105,004 — Net cash from financing activities (188,592 ) (105,302 ) 105,004 (188,890 ) Net change in cash, cash equivalents and restricted cash (8,436 ) — — (8,436 ) Cash, cash equivalents and restricted cash, beginning of period 9,399 — — 9,399 Cash, cash equivalents and restricted cash, end of period $ 963 $ — $ — $ 963 Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 625,206 $ 264,096 $ — $ 889,302 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (482,534 ) (463,816 ) — (946,350 ) Capital expenditures for other properties and equipment (9,806 ) (1,249 ) — (11,055 ) Acquisition of crude oil and natural gas properties (179,955 ) (71 ) — (180,026 ) Proceeds from sale of properties and equipment 1,929 1,633 — 3,562 Proceeds from divestiture 44,693 — — 44,693 Restricted cash 1,249 — — 1,249 Intercompany transfers (199,584 ) — 199,584 — Net cash from investing activities (824,008 ) (463,503 ) 199,584 (1,087,927 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,072,500 — — 1,072,500 Repayment of revolving credit facility (1,040,000 ) — — (1,040,000 ) Payment of debt issuance costs (7,704 ) — — (7,704 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (5,147 ) — — (5,147 ) Principal payments under financing lease obligations (1,318 ) (177 ) — (1,495 ) Other (55 ) — — (55 ) Intercompany transfers — 199,584 (199,584 ) — Net cash from financing activities 18,276 199,407 (199,584 ) 18,099 Net change in cash, cash equivalents and restricted cash (180,526 ) — — (180,526 ) Cash, cash equivalents and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents and restricted cash, end of period $ 9,399 $ — $ — $ 9,399 Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 546,954 $ 50,859 $ — $ 597,813 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (439,897 ) (297,311 ) — (737,208 ) Capital expenditures for other properties and equipment (3,539 ) (1,555 ) — (5,094 ) Acquisition of crude oil and natural gas properties (21,000 ) 5,372 — (15,628 ) Proceeds from sale of properties and equipment 10,084 (93 ) — 9,991 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sales of short-term investments 49,890 — — 49,890 Purchases of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (239,191 ) — 239,191 — Net cash from investing activities (662,590 ) (293,587 ) 239,191 (716,986 ) Cash flows from financing activities: Proceeds from issuance of senior notes 592,366 — — 592,366 Redemption of senior notes (519,375 ) — — (519,375 ) Payment of debt issuance costs (50 ) — — (50 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (6,672 ) — — (6,672 ) Principal payments under financing lease obligations (1,092 ) (76 ) — (1,168 ) Other (103 ) — — (103 ) Intercompany transfers — 239,191 (239,191 ) — Net cash from financing activities 65,074 239,115 (239,191 ) 64,998 Net change in cash, cash equivalents and restricted cash (50,562 ) (3,613 ) — (54,175 ) Cash, cash equivalents and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents and restricted cash, end of period $ 189,925 $ — $ — $ 189,925 |
SUPPLEMENTAL INFORMATION - NATU
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES | 12 Months Ended |
Dec. 31, 2019 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental Information - Oil and Gas Exploration and Production Industries Disclosures [Text Block] | NATURAL GAS INFORMATION - UNAUDITED Net Proved Reserves All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2019 , 2018 and 2017 (as applicable), all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. The indicated index prices for our reserves, by commodity, are presented below. Average Benchmark Prices (1) As of December 31, Crude Oil (per Bbl) (2) Natural Gas (per Mcf) (2) NGLs (per Bbl) (3) 2019 $ 55.69 $ 2.58 $ 55.69 2018 65.56 3.10 65.56 2017 51.34 2.98 51.34 The netted back price used to estimate our reserves, by commodity, are presented below. Price Used to Estimate Reserves (4) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2019 $ 52.63 $ 1.50 $ 12.21 2018 61.14 2.15 23.04 2017 48.68 2.31 20.21 (1) Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. (2) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. (3) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. (4) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. The following tables present the changes in our estimated quantities of proved reserves: Crude Oil, Condensate (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved reserves, January 1, 2017 118,169 833,697 84,288 341,407 Revisions of previous estimates 28,334 96,119 8,104 52,457 Extensions, discoveries and other additions 2,923 11,541 1,158 6,005 Acquisition of reserves 18,971 289,223 19,604 86,778 Dispositions (653 ) (4,597 ) (481 ) (1,900 ) Production (12,902 ) (71,689 ) (6,981 ) (31,830 ) Proved reserves, December 31, 2017 154,842 1,154,294 105,692 452,917 Revisions of previous estimates 26,548 94,738 12,674 55,011 Extensions, discoveries and other additions 8,786 61,750 8,868 27,946 Acquisition of reserves 19,644 148,674 15,936 60,360 Dispositions (2,507 ) (35,750 ) (2,656 ) (11,121 ) Production (16,964 ) (88,017 ) (8,527 ) (40,160 ) Proved reserves, December 31, 2018 190,349 1,335,689 131,987 544,953 Revisions of previous estimates 25,875 328,290 31,559 112,147 Extensions, discoveries and other additions 1,056 10,262 1,519 4,285 Acquisition of reserves 553 4,558 448 1,761 Dispositions (1,412 ) (5,052 ) (614 ) (2,868 ) Production (19,166 ) (115,950 ) (10,923 ) (49,414 ) Proved reserves, December 31, 2019 197,255 1,557,797 153,976 610,864 Proved developed reserves, as of: December 31, 2017 46,862 365,332 35,220 142,971 December 31, 2018 61,821 443,151 43,856 179,535 December 31, 2019 66,211 554,234 55,411 213,994 Proved undeveloped reserves, as of: December 31, 2017 107,980 788,962 70,472 309,946 December 31, 2018 128,528 892,538 88,131 365,418 December 31, 2019 131,044 1,003,563 98,565 396,870 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2017 98,285 243,122 341,407 Revisions of previous estimates 18,291 34,166 52,457 Extensions, discoveries and other additions 2,292 3,713 6,005 Acquisition of reserves 1,305 85,473 86,778 Dispositions (20 ) (1,880 ) (1,900 ) Production (31,830 ) — (31,830 ) Undeveloped reserves converted to developed 54,648 (54,648 ) — Proved reserves, December 31, 2017 142,971 309,946 452,917 Revisions of previous estimates 6,284 48,727 55,011 Extensions, discoveries and other additions 7,874 20,072 27,946 Acquisition of reserves 8,758 51,602 60,360 Dispositions (4,486 ) (6,635 ) (11,121 ) Production (40,160 ) — (40,160 ) Undeveloped reserves converted to developed 58,294 (58,294 ) — Proved reserves, December 31, 2018 179,535 365,418 544,953 Revisions of previous estimates 27,452 84,695 112,147 Extensions, discoveries and other additions 4,285 — 4,285 Acquisition of reserves 441 1,320 1,761 Dispositions (474 ) (2,394 ) (2,868 ) Production (49,414 ) — (49,414 ) Undeveloped reserves converted to developed 52,169 (52,169 ) — Proved reserves, December 31, 2019 213,994 396,870 610,864 2019 Activity. During 2019 , we increased proved reserves by 65.9 MMBoe, or 12 percent , relative to December 31, 2018 . The increase in proved reserves was primarily the result of our 2019 development activities and our future drilling schedule. In 2019 , we produced 49.4 MMboe. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.3 MMBoe due to a decrease in operating costs, performance revisions and other items. We also experienced an additional increase of 10.2 MMBoe in proved developed reserves related to our current year drilling activities. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs. Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 74.2 MMBoe reflecting additional locations on proven acreage resulting from our drilling plan. Other changes impacting the increase were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 23.4 MMBoe of PUD reserves. Partially offsetting this increase was a negative revision of 12.9 MMBoe due to drilling schedule changes. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed activity for 2019 included the addition of 4.3 MMBoe of developed reserves related to three gross ( three net) newly-drilled wells. Extensions, Discoveries and Other Additions-PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2019. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and acquisitions were 0.4 MMBoe during 2019 . Acquisitions of Reserves-PUDs. We acquired 1.3 MMBoe of PUD reserves in 2019 in acreage swaps and acquisitions. Dispositions-Proved Developed Reserves . Dispositions of 0.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of 2.4 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. At December 31, 2018 , we projected a PUD reserve conversion rate of 16 percent for 2019 . During 2019 , a smaller number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 14 percent . We converted 52.2 MMBoe of PUD reserves at December 31, 2018 to proved developed reserves as of December 31, 2019 . Based on economic conditions on December 31, 2019 , our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2019 , our 2020 PUD reserve conversion rate is expected to be approximately 26 percent . The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. 2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent , relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMboe. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items. Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2018 included the addition of 7.9 MMBoe of developed reserves related to 17 gross ( 9.2 net) newly-drilled wells. Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross ( 15.0 net) PUD locations in the Delaware Basin. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 8.8 MMBoe during 2018. Acquisitions of Reserves-PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage swaps and an acquisition, respectively. Dispositions-Proved Developed Reserves . Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of 6.6 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions. At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent . We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018. 2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent , relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMBoe. Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items. Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves. Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells. Extensions, Discoveries and Other Additions-PUDs . PUD activity was comprised primarily of 3.7 MMBoe of PUD locations in the Delaware Basin. Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017. Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps. Dispositions-Proved Developed Reserves . Dispositions were related to acreage surrendered in various acreage swaps. Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions. At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling plans being extended in our Delaware Basin in the first half of 2017, our actual conversion rate was 23 percent , resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as of December 31, 2017. Results of Operations for Crude Oil and Natural Gas Producing Activities The results of operations for crude oil and natural gas producing activities are presented below. Year Ended December 31, 2019 2018 2017 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 1,307,275 $ 1,389,961 $ 913,084 Commodity price risk management gain (loss), net (162,844 ) 145,237 (3,936 ) 1,144,431 1,535,198 909,148 Expenses: Lease operating expenses 142,248 130,957 89,641 Production taxes 80,754 90,357 60,717 Transportation, gathering and processing expenses 46,353 37,403 33,220 Exploration expense 4,054 6,204 47,334 Depreciation, depletion and amortization 638,499 551,265 462,482 Accretion of asset retirement obligations 6,117 5,075 6,306 Impairment of properties and equipment 38,536 458,397 285,887 (Gain) loss on sale of properties and equipment 9,734 394 (766 ) 966,295 1,280,052 984,821 Results of operations for crude oil and natural gas producing 178,136 255,146 (75,673 ) Income tax (expense) benefit (9,869 ) (185,667 ) 47,247 Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 168,267 $ 69,479 $ (28,426 ) Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. Year Ended December 31, 2019 2018 2017 (in thousands) Acquisition of properties: (1) Proved properties $ 16,007 $ 205,253 $ 172 Unproved properties 9,567 5,477 18,914 Development costs (2) 780,851 970,970 688,165 Exploration costs: (3) Exploratory drilling 32,218 36,704 80,103 Geological and geophysical 3,017 3,401 3,881 Total costs incurred (4) $ 841,660 $ 1,221,805 $ 791,235 (1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019 , 2018 and 2017 , $308.9 million , $438.4 million and $463.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $35.3 million , $74.6 million and $32.8 million of infrastructure and pipeline costs in 2019 , 2018 and 2017 respectively. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million . We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: As of December 31, 2019 2018 (in thousands) Proved crude oil and natural gas properties $ 6,241,780 $ 5,452,613 Unproved crude oil and natural gas properties 403,379 492,594 Uncompleted wells, equipment and facilities 382,409 332,264 Capitalized costs 7,027,568 6,277,471 Less accumulated DD&A (2,982,929 ) (2,341,897 ) Capitalized costs, net $ 4,044,639 $ 3,935,574 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2019 2018 2017 (in thousands) Future estimated cash flows $ 14,590,604 $ 17,554,880 $ 12,340,407 Future estimated production costs (1) (4,530,173 ) (4,782,948 ) (3,245,627 ) Future estimated development costs (3,257,106 ) (3,632,822 ) (2,893,335 ) Future estimated income tax expense (907,382 ) (1,404,121 ) (748,494 ) Future net cash flows 5,895,943 7,734,989 5,452,951 10% annual discount for estimated timing of cash flows (2,585,609 ) (3,287,273 ) (2,572,846 ) Standardized measure of discounted future estimated net cash flows $ 3,310,334 $ 4,447,716 $ 2,880,105 (1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: Year Ended December 31, 2019 2018 2017 (in thousands) Beginning of period $ 4,447,716 $ 2,880,105 $ 1,420,629 Sales of crude oil, natural gas and NGLs production, net of production costs (1,037,920 ) (1,131,244 ) (729,506 ) Net changes in prices and production costs (1) (2,122,538 ) 936,077 841,713 Extensions, discoveries and improved recovery, less related costs 39,606 190,084 47,240 Sales of reserves (14,533 ) (42,362 ) (2,613 ) Purchases of reserves 18,816 467,807 224,483 Development costs incurred during the period 605,753 462,088 419,047 Revisions of previous quantity estimates 538,242 631,198 484,431 Changes in estimated income taxes 346,826 (232,002 ) (138,560 ) Net changes in future development costs 206,003 (123,663 ) 25,183 Accretion of discount 532,127 583,744 167,487 Timing and other (249,764 ) (174,116 ) 120,571 End of period $ 3,310,334 $ 4,447,716 $ 2,880,105 (1) Our weighted-average price, net of production costs per Boe, in our 2019 reserve report decreased to $16.18 as compared to $23.44 for 2018 and $20.08 for 2017 . The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. |
SUPPLEMENTAL INFORMATION - QUAR
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Data [Abstract] | |
Quarterly Financial Information [Text Block] | QUARTERLY FINANCIAL INFORMATION - UNAUDITED Quarterly financial data for the years ended December 31, 2019 and 2018 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. 2019 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 134,500 $ 390,658 $ 365,943 $ 265,022 Total costs, expenses and other 275,120 280,623 321,562 267,713 Income (loss) from operations (140,620 ) 110,035 44,381 (2,691 ) Income (loss) before income taxes (157,588 ) 91,135 26,570 (20,111 ) Net income (loss) $ (120,176 ) $ 68,548 $ 15,908 $ (20,952 ) Earnings per share: Basic $ (1.82 ) $ 1.04 $ 0.25 $ (0.34 ) Diluted (1.82 ) 1.04 0.25 (0.34 ) 2018 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 260,600 $ 212,531 $ 280,717 $ 794,811 Total costs, expenses and other 260,924 400,770 270,593 538,626 Income (loss) from operations (324 ) (188,239 ) 10,124 256,185 Income (loss) before income taxes (17,705 ) (205,580 ) (7,310 ) 238,024 Net income (loss) $ (13,139 ) $ (160,257 ) $ (3,434 ) $ 178,853 Earnings per share: Basic $ (0.20 ) $ (2.43 ) $ (0.05 ) $ 2.71 Diluted (0.20 ) (2.43 ) (0.05 ) 2.71 |
SCHEDULE II - VALUATION AND QUA
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Notes) | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block] | Schedule II -VALUATION AND QUALIFYING ACCOUNTS Description Beginning Charged to Deductions (1) Ending (in thousands) 2019: Allowance for doubtful accounts $ 4,381 $ 3,209 $ 114 $ 7,476 Allowance for expirations of unproved crude oil and natural gas properties 542,709 8,523 544,351 6,881 2018: Allowance for doubtful accounts 3,128 1,276 23 4,381 Allowance for expirations of unproved crude oil and natural gas properties 251,159 388,068 96,518 542,709 2017: Allowance for uncollectible notes $ 44,038 $ — $ 44,038 $ — Allowance for doubtful accounts 2,190 1,108 170 3,128 Allowance for expirations of unproved crude oil and natural gas properties 359 263,817 13,017 251,159 (1) For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill [Line Items] | |
Cash and Cash Equivalents, Policy [Policy Text Block] | We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. |
Derivative Financial Instruments, Policy [Policy Text Block] | We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. |
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block] | We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. |
Property, Plant and Equipment, Policy [Policy Text Block] | Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . Total depreciation expense related to other property and equipment was $5.7 million , $8.5 million and $6.6 million in 2019 , 2018 and 2017 , respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. |
Proved and Unproved Property, Impairment [Policy Text Block] | Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. |
Property, Plant and Equipment, Estimated Useful Lives [Policy Text Block] | Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . Total depreciation expense related to other property and equipment was $5.7 million , $8.5 million and $6.6 million in 2019 , 2018 and 2017 , respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. |
Internal Use Software, Policy [Policy Text Block] | Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018 , our capitalized costs for internal-use software were $25.9 million and $1.4 million , respectively. |
Interest Capitalization, Policy [Policy Text Block] | Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million , $9.2 million and $5.0 million in 2019 , 2018 and 2017 , respectively. |
Assets Held For Sale, Policy [Policy Text Block] | Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. |
Income Tax, Policy [Policy Text Block] | We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. |
Debt Issuance Costs, Policy [Policy Text Block] | Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. |
Asset Retirement Obligation [Policy Text Block] | We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, |
Treasury Shares, Policy [Policy Text Block] | We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. |
Revenue [Policy Text Block] | Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019 , 2018 and 2017 , the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. |
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block] | Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. |
Accounting for Acquisitions using Purchase Accounting [Policy Text Block] | We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. |
Stock-Based Compensation, Policy [Policy Text Block] | Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. |
Earnings Per Share, Policy [Policy Text Block] | Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. |
Consolidation, Policy [Policy Text Block] | All material intercompany accounts and transactions have been eliminated in consolidation. |
Use of Estimates, Policy [Policy Text Block] | The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets |
Asset Exchange [Policy Text Block] | From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . |
New Accounting Pronouncement, Early Adoption [Table Text Block] | In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million , other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings. |
Goodwill Disclosure [Text Block] | GOODWILL Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $75.1 million . In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. The quantitative test resulted in a determination that a full impairment charge of $75.1 million |
Significant Accounting Policies [Text Block] | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. Restricted Cash. At December 31, 2018 , our total cash, cash equivalents and restricted cash of $9.4 million was comprised of $1.4 million of cash and cash equivalents and $8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018 . We did not have any restricted cash at December 31, 2019 . Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Properties and Equipment. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . Total depreciation expense related to other property and equipment was $5.7 million , $8.5 million and $6.6 million in 2019 , 2018 and 2017 , respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018 , our capitalized costs for internal-use software were $25.9 million and $1.4 million , respectively. Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million , $9.2 million and $5.0 million in 2019 , 2018 and 2017 , respectively. Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019 , 2018 and 2017 , the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. Recently Adopted Accounting Standards. In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million , other accrued expenses of $4.6 million and other liabilities of $15.5 million |
Revenue Recognition Revenue R_2
Revenue Recognition Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue [Table Text Block] | REVENUE RECOGNITION On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. The adoption of the New Revenue Standard has not significantly impacted our net income. Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2019 , 2018 and 2017 : Year Ended December 31, Revenue by Commodity and Operating Region 2019 2018 2017 (1) (in thousands) Crude oil Wattenberg Field $ 767,760 $ 783,158 $ 529,562 Delaware Basin 252,929 252,107 82,677 Utica Shale (2) — 2,696 12,814 Total $ 1,020,689 $ 1,037,961 $ 625,053 Natural gas Wattenberg Field $ 137,143 $ 130,073 $ 131,792 Delaware Basin 13,877 32,010 21,251 Utica Shale (2) — 1,109 5,216 Total $ 151,020 $ 163,192 $ 158,259 NGLs Wattenberg Field $ 94,347 $ 132,820 $ 104,298 Delaware Basin 41,219 55,148 20,756 Utica Shale (2) — 840 4,718 Total $ 135,566 $ 188,808 $ 129,772 Revenue by Operating Region Wattenberg Field $ 999,250 $ 1,046,051 $ 765,652 Delaware Basin 308,025 339,265 124,684 Utica Shale (2) — 4,645 22,748 Total $ 1,307,275 $ 1,389,961 $ 913,084 (1) As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 have not been restated. Such changes would not have been material. (2) In March 2018, we completed the disposition of our Utica Shale properties. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: As of December 31, 2019 2018 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 22,886 $ 8,938 $ 31,824 $ 118,521 $ 59,693 $ 178,214 Total liabilities (3,089 ) (524 ) (3,613 ) (3,364 ) (1,364 ) (4,728 ) Net asset $ 19,797 $ 8,414 $ 28,211 $ 115,157 $ 58,329 $ 173,486 |
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block] | The following table presents a reconciliation of our Level 3 assets measured at fair value: Year Ended December 31, 2019 2018 2017 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 58,329 $ (9,687 ) $ (9,574 ) Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net (41,749 ) 63,257 6,241 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net (8,166 ) 4,759 (6,354 ) Fair value of Level 3 instruments, net asset (liability) end of period $ 8,414 $ 58,329 $ (9,687 ) Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (22,694 ) $ — $ (866 ) Total $ (22,694 ) $ — $ (866 ) |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2019 and 2018 : As of December 31, 2019 2018 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 188.6 94.3 % $ 175.4 87.7 % 2024 Senior Notes 409.2 102.3 % 370.2 92.5 % 2026 Senior Notes 599.4 99.9 % 532.4 88.7 % |
Concentration of Risk Accounts
Concentration of Risk Accounts Receivable, net of Allowance for Doubtful Accounts (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Concentration Risks, Types, No Concentration Percentage [Abstract] | |
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block] | Other Accrued Expenses. The following table presents the components of other accrued expenses: As of December 31, 2019 2018 (in thousands) Employee benefits $ 21,611 $ 25,811 Asset retirement obligations 32,200 25,598 Environmental expenses 2,256 3,038 Operating and finance leases 5,926 1,779 Other 8,469 18,907 Other accrued expenses $ 70,462 $ 75,133 Other Liabilities. The following table presents the components of other liabilities as of: As of December 31, 2019 2018 (in thousands) Production taxes $ 68,020 $ 61,310 Deferred oil gathering credits 20,100 22,710 Deferred midstream gathering credits 175,897 — Operating and finance leases 15,779 2,900 Other 3,337 5,744 Other liabilities $ 283,133 $ 92,664 Deferred Oil Gathering Credits. In January 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment is being amortized over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $2.0 million and $1.4 million for 2019 and 2018 , respectively, are included as a reduction to transportation, gathering and processing expenses. Deferred Midstream Gathering Credits. In May 2019, concurrent with the sale of our Delaware Basin produced water gathering and disposal midstream assets, we entered into an agreement with the purchaser which dedicates all of our water gathering and disposal volumes in the Delaware Basin via pipeline for a term of 15 years . We recorded a long-term deferred credit of $40.5 million attributable to the value of the dedication, which is being amortized using the units-of-production basis. Amortization charges related to this deferred credit totaling $0.9 million for 2019 are included as a reduction to lease operating expenses and capital costs. In May 2019, concurrent with the sale of our Delaware Basin crude oil gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering and transport for crude oil from dedicated acreage within an area of mutual interest for a term of 15 years . We recorded a long-term deferred credit of $28.9 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $0.5 million for 2019 are included as crude oil sales. In June 2019, concurrent with the sale of our Delaware Basin natural gas gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering, processing and transportation of our natural gas from certain dedicated leases for a term of 22 years . We recorded a long-term deferred credit of $110.2 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $2.0 million for 2019 are included as a reduction to transportation, gathering and processing expenses. |
Accounts Receivable [Table Text Block] | Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: As of December 31, 2019 2018 (in thousands) Crude oil, natural gas and NGLs sales $ 149,758 $ 155,756 Joint interest billings 29,510 19,580 Midstream asset divestitures deferred payments 81,702 — Derivative counterparties — 3,937 Other 12,860 6,542 Allowance for doubtful accounts (7,476 ) (4,381 ) Accounts receivable, net $ 266,354 $ 181,434 |
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block] | Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: Year Ended December 31, Customer 2019 2018 2017 Occidental Marketing, Inc. 20.0 % — % — % DCP Midstream, LP 17.0 % 12.5 % 19.6 % Mercuria Energy Trading, Inc. 16.0 % — % — % United Energy Trading, LLC 11.0 % — % — % Suncor Energy Marketing, Inc. — % — % 16.4 % |
Derivative Financial Instrume_2
Derivative Financial Instruments Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | As of December 31, 2019 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. Collars Fixed-Price Swaps Commodity/ Index/ Maturity Period Quantity (Crude oil - MBls Natural Gas - BBtu) Weighted-Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted- Average Contract Price Fair Value December 31, 2019 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2020 3,600 55.00 71.68 7,160 60.98 27,162 2021 — — — 3,200 55.76 3,054 Total Crude Oil 3,600 10,360 $ 30,216 Natural Gas NYMEX 2020 — — — 4,000 2.30 75 Dominion South 2020 — — — 14 2.54 — Total Natural Gas — 4,014 $ 75 Basis Protection - Natural Gas CIG 2020 — $ — $ — 20,500 $ (0.62 ) $ (2,392 ) Waha 2020 — — — 4,000 (1.40 ) 312 Total Basis Protection - Natural Gas — 24,500 $ (2,080 ) Commodity Derivatives Fair Value $ 28,211 (1) Approximately 28.1 percent of the fair value of our commodity derivative assets and 14.5 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). |
Derivatives Not Designated as Hedging Instruments [Table Text Block] | The following table presents the balance sheet location and fair value amounts of our derivative instruments as of December 31, 2019 and 2018 : Fair Value Derivative Instruments: Consolidated Balance Sheet Line Item 2019 2018 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 27,766 $ 84,492 Basis protection derivative contracts Fair value of derivatives 312 — 28,078 84,492 Non-current Commodity derivative contracts Fair value of derivatives 3,746 93,722 Total derivative assets $ 31,824 $ 178,214 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 529 748 Basis protection derivative contracts Fair value of derivatives 2,392 2,616 2,921 3,364 Non-current Commodity derivative contracts Fair value of derivatives 692 1,364 Total derivative liabilities $ 3,613 $ 4,728 The following table presents the impact of our derivative instruments on our consolidated statements of operations: Year Ended December 31, Consolidated Statements of Operations Line Item 2019 2018 2017 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (17,598 ) $ (115,538 ) $ 13,324 Net change in fair value of unsettled derivatives (145,246 ) 260,775 (17,260 ) Total commodity price risk management gain (loss), net $ (162,844 ) $ 145,237 $ (3,936 ) Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2019 Derivative Instruments, Gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 31,824 $ (2,619 ) $ 29,205 Liability derivatives: Derivative instruments, at fair value $ 3,613 $ (2,619 ) $ 994 As of December 31, 2018 Derivative instruments, gross Effect of Master Netting Agreements Derivative Instruments, Net (in thousands) Asset derivatives: Derivative instruments, at fair value $ 178,214 $ (3,985 ) $ 174,229 Liability derivatives: Derivative instruments, at fair value $ 4,728 $ (3,985 ) $ 743 |
Properties and Equipment Proper
Properties and Equipment Properties and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block] | The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment: As of December 31, 2019 2018 (in thousands, except for number of wells) Beginning balance $ 12,188 $ 15,448 Additions to capitalized exploratory well costs pending the determination of proved reserves 31,901 35,127 Reclassifications to proved properties (28,011 ) (38,387 ) Ending balance $ 16,078 $ 12,188 Number of wells pending determination at period-end 4 2 |
Property, Plant and Equipment [Table Text Block] | The following table presents the components of properties and equipment, net of accumulated DD&A: As of December 31, 2019 2018 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 6,241,780 $ 5,452,613 Unproved 403,379 492,594 Total crude oil and natural gas properties 6,645,159 5,945,207 Infrastructure and other 41,888 60,612 Land and buildings 12,312 11,243 Construction in progress 408,428 356,095 Properties and equipment, at cost 7,107,787 6,373,157 Accumulated DD&A (3,012,585 ) (2,370,295 ) Properties and equipment, net $ 4,095,202 $ 4,002,862 |
Impairment of natural gas and crude oil properties [Table Text Block] | he following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2019 2018 2017 (in thousands) Impairment of proved and unproved properties $ 10,599 $ 458,397 $ 285,465 Amortization of individually insignificant unproved properties — — 422 Impairment of infrastructure and other 27,937 — — Total impairment of properties and equipment $ 38,536 $ 458,397 $ 285,887 |
Properties and Equipment Explor
Properties and Equipment Exploration, Geologic, and Geophysical Expense (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2019 2018 2017 (in thousands) Exploratory dry hole costs $ — $ 113 $ 41,297 Geological and geophysical costs, including seismic purchases 3,017 3,401 3,881 Operating, personnel and other 1,037 2,690 2,156 Total exploration, geologic and geophysical expense $ 4,054 $ 6,204 $ 47,334 Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. Year Ended December 31, 2019 2018 2017 (in thousands) Acquisition of properties: (1) Proved properties $ 16,007 $ 205,253 $ 172 Unproved properties 9,567 5,477 18,914 Development costs (2) 780,851 970,970 688,165 Exploration costs: (3) Exploratory drilling 32,218 36,704 80,103 Geological and geophysical 3,017 3,401 3,881 Total costs incurred (4) $ 841,660 $ 1,221,805 $ 791,235 (1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019 , 2018 and 2017 , $308.9 million , $438.4 million and $463.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $35.3 million , $74.6 million and $32.8 million of infrastructure and pipeline costs in 2019 , 2018 and 2017 respectively. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million . We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. |
Properties and Equipment Assets
Properties and Equipment Assets held-for-sale (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Disclosure of Long Lived Assets Held-for-sale [Table Text Block] | December 31, 2018 (in thousands) Assets Properties and equipment, net $ 137,448 Other assets 3,257 Total assets $ 140,705 Liabilities Asset retirement obligation $ 4,111 Total liabilities $ 4,111 |
Leases Operating and Financin_2
Leases Operating and Financing Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lease, Cost [Table Text Block] | The following table presents the components of lease costs: Lease Costs Year Ended December 31, 2019 (in thousands) Operating lease costs $ 4,917 Finance lease costs: Amortization of ROU assets $ 1,961 Interest on lease liabilities 252 Total finance lease costs $ 2,213 Short-term lease costs 170,064 Total lease costs $ 177,194 |
Operating and Financing Leases Financial Statement Location [Table Text Block] | The following table presents the balance sheet classification and other information regarding our leases as of: Leases Consolidated Balance Sheet Line Item December 31, 2019 (in thousands) Operating Leases: Operating lease ROU assets Other assets $ 14,926 Operating lease obligation - short-term Other accrued expense $ 4,159 Operating lease obligation - long-term Other liabilities 12,944 Total operating lease liabilities $ 17,103 Finance Leases: Finance lease ROU assets Properties and equipment, net $ 4,637 Finance lease obligation - short-term Other accrued expense $ 1,767 Finance lease obligation - long-term Other liabilities 2,835 Total finance lease liabilities $ 4,602 Weighted-average remaining lease term (years) Operating leases 4.28 Finance leases 3.17 Weighted-average discount rate Operating leases 5.0 % Finance leases 5.0 % |
Finance Lease, Liability, Maturity [Table Text Block] | Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2019 consist of the following: Operating Leases Finance Leases Total (in thousands) 2020 $ 4,847 $ 1,949 $ 6,796 2021 4,923 1,423 6,346 2022 5,016 855 5,871 2023 1,559 637 2,196 2024 950 95 1,045 Thereafter 1,698 — 1,698 Total lease payments 18,993 4,959 23,952 Less: Interest and discount (1,890 ) (357 ) (2,247 ) Present value of lease liabilities $ 17,103 $ 4,602 $ 21,705 |
Asset Retirement Obligations As
Asset Retirement Obligations Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: Year Ended December 31, 2019 2018 (in thousands) Beginning balance $ 115,021 $ 87,306 Obligations incurred with development activities 4,605 2,793 Obligations incurred with acquisition 2,882 4,332 Accretion expense 6,117 5,075 Revisions in estimated cash flows 28,991 30,166 Obligations discharged with asset retirements (23,426 ) (14,651 ) Obligations discharged with divestitures (6,939 ) — Balance at December 31 127,251 115,021 Liabilities held-for-sale — (4,111 ) Current portion (32,200 ) (25,598 ) Long-term portion $ 95,051 $ 85,312 |
Long-Term Debt LONG-TERM DEBT (
Long-Term Debt LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | Long-term debt consisted of the following as of: As of December 31, 2019 2018 (in thousands) Senior Notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (14,763 ) (22,766 ) Unamortized debt issuance costs (1,666 ) (2,640 ) Net of unamortized discount and debt issuance costs 183,571 174,594 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (4,611 ) (5,590 ) Net of unamortized debt issuance costs 395,389 394,410 5.75% Senior Notes due May 2026: Principal amount 600,000 600,000 Unamortized debt issuance costs (5,734 ) (6,628 ) Net of unamortized debt issuance costs 594,266 593,372 Total senior notes 1,173,226 1,162,376 Revolving Credit Facility: Revolving credit facility due May 2023 4,000 32,500 Total long-term debt, net of unamortized discount and debt issuance costs $ 1,177,226 $ 1,194,876 |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contigencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Supply Commitment [Table Text Block] | The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: Year Ending December 31, Area 2020 2021 2022 2023 Thereafter Total Expiration Natural gas (MMcf) Wattenberg Field 30,608 31,025 31,025 31,025 63,992 187,675 August 31, 2026 Delaware Basin 37,552 28,241 9,125 9,125 66,175 150,218 March 31, 2031 Gas Marketing 7,136 7,056 4,495 — — 18,687 August 31, 2022 Total 75,296 66,322 44,645 40,150 130,167 356,580 Crude oil (MBbls) Wattenberg Field 9,992 16,243 16,243 12,567 37,255 92,300 December 31, 2027 Delaware Basin 8,784 8,030 8,030 8,030 — 32,874 December 31, 2023 Total 18,776 24,273 24,273 20,597 37,255 125,174 Water (MBbls) Wattenberg Field 6,224 6,207 6,207 6,206 6,223 31,067 December 31, 2024 Total 6,224 6,207 6,207 6,206 6,223 31,067 Dollar commitment (in thousands) $ 85,159 $ 106,322 $ 101,107 $ 85,774 $ 202,532 $ 580,894 |
Common Stock Common Stock (Tabl
Common Stock Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Payment Arrangement, Cost by Plan [Table Text Block] | The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2019 2018 2017 (in thousands) Stock-based compensation expense $ 23,837 $ 21,782 $ 19,353 Income tax benefit (5,780 ) (5,210 ) (7,372 ) Net stock-based compensation expense $ 18,057 $ 16,572 $ 11,981 |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] | Year Ended December 31, 2017 Expected term of award (in years) 6 Risk-free interest rate 2.0 % Expected volatility 53.3 % Weighted-average grant date fair value per share $ 38.58 |
Share-based Payment Arrangement, Stock Appreciation Right, Activity [Table Text Block] | Year Ended December 31, 2019 2018 2017 Number of Weighted-Average Average Remaining Contractual (in years) Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Number of Weighted-Average Aggregate Intrinsic Outstanding at January 1, 290,258 $ 46.64 4.6 $ 125 298,220 $ 47.39 $ 2,490 244,078 $ 41.36 $ 7,620 Awarded — — — — — — — 54,142 74.57 — Modified — — — — 63,969 42.83 — — — — Expired — — — — (71,931 ) 46.34 — — — — Outstanding at December 31, 290,258 46.64 3.6 41 290,258 46.64 125 298,220 47.39 2,490 Exercisable at December 31, 276,775 45.28 3.4 41 260,101 44.88 125 223,865 43.28 2,267 |
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block] | The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for 2019 : Shares Weighted-Average Non-vested at December 31, 2018 618,407 $ 54.16 Granted 588,899 40.34 Vested (307,450 ) 52.98 Forfeited (103,930 ) 45.62 Non-vested at December 31, 2019 795,926 45.51 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2019 2018 2017 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 11,652 $ 12,282 $ 16,303 Total intrinsic value of time-based awards non-vested 20,829 18,404 24,334 Market price per share as of December 31, 26.17 29.76 51.54 Weighted-average grant date fair value per share 40.34 50.69 65.14 |
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block] | he weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2019 2018 2017 Expected term of award (in years) 3 3 3 Risk-free interest rate 2.5 % 2.4 % 1.4 % Expected volatility 41.4 % 42.3 % 51.4 % |
Schedule of Nonvested Performance-based Units Activity [Table Text Block] | The following table presents the change in non-vested market-based awards during 2019 : Shares Weighted-Average Non-vested at December 31, 2018 102,914 $ 74.88 Granted 139,197 56.68 Vested (20,969 ) 94.02 Forfeited — — Non-vested at December 31, 2019 221,142 61.61 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2019 2018 2017 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 530 $ 620 $ 2,687 Total intrinsic value of market-based awards non-vested 5,787 3,063 2,698 Market price per share as of December 31, 26.17 29.76 51.54 Weighted-average grant date fair value per share 56.68 69.98 94.02 |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The table below presents the components of our provision for income tax (expense) benefit for the years presented: Year Ended December 31, 2019 2018 2017 (in thousands) Current: Federal $ 1,366 $ 887 $ 8,443 State (300 ) (188 ) (200 ) Total current income tax benefit 1,066 699 8,243 Deferred: Federal 4,507 (1,986 ) 193,809 State (2,251 ) (4,119 ) 9,876 Total deferred income tax (expense) benefit 2,256 (6,105 ) 203,685 Income tax (expense) benefit $ 3,322 $ (5,406 ) $ 211,928 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: Year Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % State income tax, net 3.6 (6.4 ) 1.8 Federal tax credits (3.3 ) (52.1 ) — Effect of state income tax rate changes (6.4 ) 6.7 — Change in valuation allowance (0.6 ) 45.5 — Non-deductible compensation (5.0 ) 21.8 (0.3 ) Non-deductible acquisition costs (2.3 ) — — Non-deductible government relations (1.0 ) 31.8 — Other non-deductible items (0.5 ) 4.9 — Federal tax reform rate reduction — — 33.7 Non-deductible goodwill impairment — — (7.7 ) Other — (0.4 ) (0.1 ) Effective tax rate 5.5 % 72.8 % 62.4 % |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | ax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 are presented below. As of December 31, 2019 2018 (in thousands) Deferred tax assets: Deferred compensation $ 9,905 $ 9,963 Asset retirement obligations 30,993 27,166 Federal NOL carryforward 22,965 54,736 State NOL and tax credit carryforwards, net 9,508 13,223 Federal tax - credit carryforwards 4,448 7,756 Prepaid revenue 4,874 5,288 Other 3,887 4,647 Valuation allowance (3,775 ) (3,380 ) Total gross deferred tax assets 82,805 119,399 Deferred tax liabilities: Properties and equipment 268,234 270,565 Net change in fair value of unsettled derivatives 6,841 41,496 Convertible debt 3,571 5,434 Total gross deferred tax liabilities 278,646 317,495 Net deferred tax liability $ 195,841 $ 198,096 |
Earnings per share (Tables)
Earnings per share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation [Table Text Block] | The following table presents our weighted-average basic and diluted shares outstanding: Year Ended December 31, 2019 2018 2017 (in thousands) Weighted-average common shares outstanding - basic 64,032 66,059 65,837 Dilutive effect of: RSUs and PSUs — 173 — Other equity-based awards — 71 — Weighted-average common shares and equivalents outstanding - diluted 64,032 66,303 65,837 |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block] | The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: Year Ended December 31, 2019 2018 2017 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 989 145 590 Other equity-based awards 302 109 75 Total anti-dilutive common share equivalents 1,291 254 665 |
Supplemental Cash Flow Supple_2
Supplemental Cash Flow Supplemental Cash Flow (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | Year Ended December 31, 2019 2018 (1) 2017 (1) (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 57,439 $ 55,586 $ 69,880 Income taxes (1,167 ) (6,719 ) (13,925 ) Non-cash investing and financing activities: Change in accounts payable related to capital expenditures (68,246 ) 36,328 50,761 Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal 29,533 37,136 839 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5,301 $ — $ — Operating cash flows from finance leases 253 — — Financing cash flows from finance leases 1,952 — — ROU assets obtained in exchange for lease obligations: Operating leases $ 1,428 $ — $ — Finance leases 2,323 — — |
Subsidiary Guarantor SUBSIDIA_2
Subsidiary Guarantor SUBSIDIARY GUARANTOR (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Guarantor Obligations [Line Items] | |
Schedule of Guarantor Obligations [Table Text Block] | SUBSIDIARY GUARANTOR PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for: (i) PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; (ii) PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; (iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and (iv) Parent and subsidiaries on a consolidated basis ("Consolidated"). The Guarantor is 100 percent owned by the Parent. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. Consolidating Balance Sheets December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 963 $ — $ — $ 963 Accounts receivable, net 140,742 125,612 — 266,354 Fair value of derivatives 28,078 — — 28,078 Prepaid expenses and other current assets 8,204 431 — 8,635 Total current assets 177,987 126,043 — 304,030 Properties and equipment, net 2,328,337 1,766,865 — 4,095,202 Intercompany receivable 348,818 — (348,818 ) — Investment in subsidiaries 1,286,931 — (1,286,931 ) — Fair value of derivatives 3,746 — — 3,746 Other assets 38,863 6,839 — 45,702 Total Assets $ 4,184,682 $ 1,899,747 $ (1,635,749 ) $ 4,448,680 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 72,212 $ 26,722 $ — $ 98,934 Production tax liability 67,509 8,727 — 76,236 Fair value of derivatives 2,921 — — 2,921 Funds held for distribution 83,072 15,321 — 98,393 Accrued interest payable 14,281 3 — 14,284 Other accrued expenses 68,803 1,659 — 70,462 Total current liabilities 308,798 52,432 — 361,230 Intercompany payable — 348,818 (348,818 ) — Long-term debt 1,177,226 — — 1,177,226 Deferred income taxes 169,520 26,321 — 195,841 Asset retirement obligations 87,749 7,302 — 95,051 Fair value of derivatives 692 — — 692 Other liabilities 105,190 177,943 — 283,133 Total liabilities 1,849,175 612,816 (348,818 ) 2,113,173 Commitments and contingent liabilities Stockholders' equity Common shares 617 — — 617 Additional paid-in capital 2,384,309 1,766,775 (1,766,775 ) 2,384,309 Retained deficit (47,945 ) (479,844 ) 479,844 (47,945 ) Treasury shares (1,474 ) — — (1,474 ) Total stockholders' equity 2,335,507 1,286,931 (1,286,931 ) 2,335,507 Total Liabilities and Stockholders' Equity $ 4,184,682 $ 1,899,747 $ (1,635,749 ) $ 4,448,680 Consolidating Balance Sheets December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Assets Current assets: Cash and cash equivalents $ 1,398 $ — $ — $ 1,398 Accounts receivable, net 146,529 34,905 — 181,434 Fair value of derivatives 84,492 — — 84,492 Prepaid expenses and other current assets 6,725 411 — 7,136 Total current assets 239,144 35,316 — 274,460 Properties and equipment, net 2,270,711 1,732,151 — 4,002,862 Assets held-for-sale, net — 140,705 — 140,705 Intercompany receivable 451,601 — (451,601 ) — Investment in subsidiaries 1,316,945 — (1,316,945 ) — Fair value of derivatives 93,722 — — 93,722 Other assets 30,084 2,312 — 32,396 Total Assets $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Liabilities and Stockholders' Equity Liabilities Current liabilities: Accounts payable $ 110,847 $ 71,017 $ — $ 181,864 Production tax liability 53,309 7,410 — 60,719 Fair value of derivatives 3,364 — — 3,364 Funds held for distribution 90,183 15,601 — 105,784 Accrued interest payable 14,143 7 — 14,150 Other accrued expenses 73,689 1,444 — 75,133 Total current liabilities 345,535 95,479 — 441,014 Intercompany payable — 451,601 (451,601 ) — Long-term debt 1,194,876 — — 1,194,876 Deferred income taxes 162,368 35,728 — 198,096 Asset retirement obligations 79,904 5,408 — 85,312 Liabilities held-for-sale — 4,111 — 4,111 Fair value of derivatives 1,364 — — 1,364 Other liabilities 91,452 1,212 — 92,664 Total liabilities 1,875,499 593,539 (451,601 ) 2,017,437 Commitments and contingent liabilities Stockholders' equity Common shares 661 — — 661 Additional paid-in capital 2,519,423 1,766,775 (1,766,775 ) 2,519,423 Retained earnings (deficit) 8,727 (449,830 ) 449,830 8,727 Treasury shares (2,103 ) — — (2,103 ) Total stockholders' equity 2,526,708 1,316,945 (1,316,945 ) 2,526,708 Total Liabilities and Stockholders' Equity $ 4,402,207 $ 1,910,484 $ (1,768,546 ) $ 4,544,145 Consolidating Statements of Operations Year Ended December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 999,250 $ 308,025 $ — $ 1,307,275 Commodity price risk management loss, net (162,844 ) — — (162,844 ) Other income 10,972 720 — 11,692 Total revenues 847,378 308,745 — 1,156,123 Costs, expenses and other Lease operating expenses 94,829 47,419 — 142,248 Production taxes 61,577 19,177 — 80,754 Transportation, gathering and processing expenses 23,719 22,634 — 46,353 Exploration, geologic and geophysical expense 1,111 2,943 — 4,054 General and administrative expense 144,345 17,408 — 161,753 Depreciation, depletion and amortization 451,282 192,870 — 644,152 Accretion of asset retirement obligations 5,446 671 — 6,117 Impairment of properties and equipment 292 38,244 — 38,536 (Gain) loss on sale of properties and equipment (853 ) 10,587 — 9,734 Other expenses 11,317 — — 11,317 Total costs, expenses and other 793,065 351,953 — 1,145,018 Income (loss) from operations 54,313 (43,208 ) — 11,105 Interest expense (75,257 ) 4,086 — (71,171 ) Interest income 71 1 — 72 Loss before income taxes (20,873 ) (39,121 ) — (59,994 ) Income tax (expense) benefit (5,784 ) 9,106 — 3,322 Equity in loss of subsidiary (30,015 ) — 30,015 — Net loss $ (56,672 ) $ (30,015 ) $ 30,015 $ (56,672 ) Consolidating Statements of Operations Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas and NGLs sales $ 1,050,696 $ 339,265 $ — $ 1,389,961 Commodity price risk management gain, net 145,237 — — 145,237 Other income 10,744 2,717 — 13,461 Total revenues 1,206,677 341,982 — 1,548,659 Costs, expenses and other Lease operating expenses 92,228 38,729 — 130,957 Production taxes 67,819 22,538 — 90,357 Transportation, gathering and processing expenses 16,607 20,796 — 37,403 Exploration, geologic and geophysical expense 1,234 4,970 — 6,204 General and administrative expense 152,798 17,706 — 170,504 Depreciation, depletion and amortization 389,841 169,952 — 559,793 Accretion of asset retirement obligations 4,617 458 — 5,075 Impairment of properties and equipment 27 458,370 — 458,397 (Gain) loss on sale of properties and equipment (4,387 ) 4,781 — 394 Other expenses 11,829 — — 11,829 Total costs, expenses and other 732,613 738,300 — 1,470,913 Income (loss) from operations 474,064 (396,318 ) — 77,746 Interest expense (73,251 ) 2,521 — (70,730 ) Interest income 413 — — 413 Income (loss) before income taxes 401,226 (393,797 ) — 7,429 Income tax (expense) benefit (98,611 ) 93,205 — (5,406 ) Equity in loss of subsidiary (300,592 ) — 300,592 — Net income (loss) $ 2,023 $ (300,592 ) $ 300,592 $ 2,023 Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. Consolidating Statements of Operations Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Revenues Crude oil, natural gas, and NGLs sales $ 788,400 $ 124,684 $ — $ 913,084 Commodity price risk management loss, net (3,936 ) — — (3,936 ) Other income 11,901 567 — 12,468 Total revenues 796,365 125,251 — 921,616 Costs, expenses and other Lease operating expenses 68,031 21,610 — 89,641 Production taxes 53,236 7,481 — 60,717 Transportation, gathering and processing expenses 23,301 9,919 — 33,220 Exploration, geologic and geophysical expense 1,092 46,242 — 47,334 General and administrative expense 107,518 12,852 — 120,370 Depreciation, depletion and amortization 403,984 65,100 — 469,084 Accretion of asset retirement obligations 5,965 341 — 6,306 Impairment of properties and equipment 4,951 280,936 — 285,887 Impairment of goodwill — 75,121 — 75,121 Gain on sale of properties and equipment (766 ) — — (766 ) Provision for uncollectible notes receivable (40,203 ) — — (40,203 ) Other expenses 13,157 — — 13,157 Total costs, expenses and other 640,266 519,602 — 1,159,868 Income (loss) from operations 156,099 (394,351 ) — (238,252 ) Loss on extinguishment of debt (24,747 ) — — (24,747 ) Interest expense (79,919 ) 1,225 — (78,694 ) Interest income 2,261 — — 2,261 Income (loss) before income taxes 53,694 (393,126 ) — (339,432 ) Income tax (expense) benefit (33,643 ) 245,571 — 211,928 Equity in loss of subsidiary (147,555 ) — 147,555 — Net loss $ (127,504 ) $ (147,555 ) $ 147,555 $ (127,504 ) Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill. Consolidating Statements of Cash Flows Year Ended December 31, 2019 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 579,464 $ 278,762 $ — $ 858,226 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (485,725 ) (370,183 ) — (855,908 ) Capital expenditures for other properties and equipment (20,361 ) (478 ) — (20,839 ) Acquisition of crude oil and natural gas properties (12,141 ) (1,066 ) — (13,207 ) Proceeds from sale of properties and equipment 399 1,706 — 2,105 Proceeds from divestiture 5,515 196,561 — 202,076 Restricted cash 8,001 — — 8,001 Intercompany transfers 105,004 — (105,004 ) — Net cash from investing activities (399,308 ) (173,460 ) (105,004 ) (677,772 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,577,000 — — 1,577,000 Repayment of revolving credit facility (1,605,500 ) — — (1,605,500 ) Payment of debt issuance costs (72 ) — — (72 ) Purchase of treasury stock (154,363 ) — — (154,363 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (4,003 ) — — (4,003 ) Principal payments under financing lease obligations (1,654 ) (298 ) — (1,952 ) Intercompany transfers — (105,004 ) 105,004 — Net cash from financing activities (188,592 ) (105,302 ) 105,004 (188,890 ) Net change in cash, cash equivalents and restricted cash (8,436 ) — — (8,436 ) Cash, cash equivalents and restricted cash, beginning of period 9,399 — — 9,399 Cash, cash equivalents and restricted cash, end of period $ 963 $ — $ — $ 963 Consolidating Statements of Cash Flows Year Ended December 31, 2018 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 625,206 $ 264,096 $ — $ 889,302 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (482,534 ) (463,816 ) — (946,350 ) Capital expenditures for other properties and equipment (9,806 ) (1,249 ) — (11,055 ) Acquisition of crude oil and natural gas properties (179,955 ) (71 ) — (180,026 ) Proceeds from sale of properties and equipment 1,929 1,633 — 3,562 Proceeds from divestiture 44,693 — — 44,693 Restricted cash 1,249 — — 1,249 Intercompany transfers (199,584 ) — 199,584 — Net cash from investing activities (824,008 ) (463,503 ) 199,584 (1,087,927 ) Cash flows from financing activities: Proceeds from revolving credit facility 1,072,500 — — 1,072,500 Repayment of revolving credit facility (1,040,000 ) — — (1,040,000 ) Payment of debt issuance costs (7,704 ) — — (7,704 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (5,147 ) — — (5,147 ) Principal payments under financing lease obligations (1,318 ) (177 ) — (1,495 ) Other (55 ) — — (55 ) Intercompany transfers — 199,584 (199,584 ) — Net cash from financing activities 18,276 199,407 (199,584 ) 18,099 Net change in cash, cash equivalents and restricted cash (180,526 ) — — (180,526 ) Cash, cash equivalents and restricted cash, beginning of period 189,925 — — 189,925 Cash, cash equivalents and restricted cash, end of period $ 9,399 $ — $ — $ 9,399 Consolidating Statements of Cash Flows Year Ended December 31, 2017 Parent Guarantor Eliminations Consolidated (in thousands) Cash flows from operating activities $ 546,954 $ 50,859 $ — $ 597,813 Cash flows from investing activities: Capital expenditures for development of crude oil and natural gas properties (439,897 ) (297,311 ) — (737,208 ) Capital expenditures for other properties and equipment (3,539 ) (1,555 ) — (5,094 ) Acquisition of crude oil and natural gas properties (21,000 ) 5,372 — (15,628 ) Proceeds from sale of properties and equipment 10,084 (93 ) — 9,991 Sale of promissory note 40,203 — — 40,203 Restricted cash (9,250 ) — — (9,250 ) Sales of short-term investments 49,890 — — 49,890 Purchases of short-term investments (49,890 ) — — (49,890 ) Intercompany transfers (239,191 ) — 239,191 — Net cash from investing activities (662,590 ) (293,587 ) 239,191 (716,986 ) Cash flows from financing activities: Proceeds from issuance of senior notes 592,366 — — 592,366 Redemption of senior notes (519,375 ) — — (519,375 ) Payment of debt issuance costs (50 ) — — (50 ) Purchase of treasury shares for employee stock-based compensation tax withholding obligations (6,672 ) — — (6,672 ) Principal payments under financing lease obligations (1,092 ) (76 ) — (1,168 ) Other (103 ) — — (103 ) Intercompany transfers — 239,191 (239,191 ) — Net cash from financing activities 65,074 239,115 (239,191 ) 64,998 Net change in cash, cash equivalents and restricted cash (50,562 ) (3,613 ) — (54,175 ) Cash, cash equivalents and restricted cash, beginning of period 240,487 3,613 — 244,100 Cash, cash equivalents and restricted cash, end of period $ 189,925 $ — $ — $ 189,925 |
SUPPLEMENTAL INFORMATION - NA_2
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Reserve Quantities [Line Items] | |
Index price for reserves, by commodity [Table Text Block] | The indicated index prices for our reserves, by commodity, are presented below. Average Benchmark Prices (1) As of December 31, Crude Oil (per Bbl) (2) Natural Gas (per Mcf) (2) NGLs (per Bbl) (3) 2019 $ 55.69 $ 2.58 $ 55.69 2018 65.56 3.10 65.56 2017 51.34 2.98 51.34 |
Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block] | The netted back price used to estimate our reserves, by commodity, are presented below. Price Used to Estimate Reserves (4) As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2019 $ 52.63 $ 1.50 $ 12.21 2018 61.14 2.15 23.04 2017 48.68 2.31 20.21 (1) Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. (2) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. (3) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. (4) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | The following tables present the changes in our estimated quantities of proved reserves: Crude Oil, Condensate (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved reserves, January 1, 2017 118,169 833,697 84,288 341,407 Revisions of previous estimates 28,334 96,119 8,104 52,457 Extensions, discoveries and other additions 2,923 11,541 1,158 6,005 Acquisition of reserves 18,971 289,223 19,604 86,778 Dispositions (653 ) (4,597 ) (481 ) (1,900 ) Production (12,902 ) (71,689 ) (6,981 ) (31,830 ) Proved reserves, December 31, 2017 154,842 1,154,294 105,692 452,917 Revisions of previous estimates 26,548 94,738 12,674 55,011 Extensions, discoveries and other additions 8,786 61,750 8,868 27,946 Acquisition of reserves 19,644 148,674 15,936 60,360 Dispositions (2,507 ) (35,750 ) (2,656 ) (11,121 ) Production (16,964 ) (88,017 ) (8,527 ) (40,160 ) Proved reserves, December 31, 2018 190,349 1,335,689 131,987 544,953 Revisions of previous estimates 25,875 328,290 31,559 112,147 Extensions, discoveries and other additions 1,056 10,262 1,519 4,285 Acquisition of reserves 553 4,558 448 1,761 Dispositions (1,412 ) (5,052 ) (614 ) (2,868 ) Production (19,166 ) (115,950 ) (10,923 ) (49,414 ) Proved reserves, December 31, 2019 197,255 1,557,797 153,976 610,864 Proved developed reserves, as of: December 31, 2017 46,862 365,332 35,220 142,971 December 31, 2018 61,821 443,151 43,856 179,535 December 31, 2019 66,211 554,234 55,411 213,994 Proved undeveloped reserves, as of: December 31, 2017 107,980 788,962 70,472 309,946 December 31, 2018 128,528 892,538 88,131 365,418 December 31, 2019 131,044 1,003,563 98,565 396,870 Developed Undeveloped Total (MBoe) Proved reserves, January 1, 2017 98,285 243,122 341,407 Revisions of previous estimates 18,291 34,166 52,457 Extensions, discoveries and other additions 2,292 3,713 6,005 Acquisition of reserves 1,305 85,473 86,778 Dispositions (20 ) (1,880 ) (1,900 ) Production (31,830 ) — (31,830 ) Undeveloped reserves converted to developed 54,648 (54,648 ) — Proved reserves, December 31, 2017 142,971 309,946 452,917 Revisions of previous estimates 6,284 48,727 55,011 Extensions, discoveries and other additions 7,874 20,072 27,946 Acquisition of reserves 8,758 51,602 60,360 Dispositions (4,486 ) (6,635 ) (11,121 ) Production (40,160 ) — (40,160 ) Undeveloped reserves converted to developed 58,294 (58,294 ) — Proved reserves, December 31, 2018 179,535 365,418 544,953 Revisions of previous estimates 27,452 84,695 112,147 Extensions, discoveries and other additions 4,285 — 4,285 Acquisition of reserves 441 1,320 1,761 Dispositions (474 ) (2,394 ) (2,868 ) Production (49,414 ) — (49,414 ) Undeveloped reserves converted to developed 52,169 (52,169 ) — Proved reserves, December 31, 2019 213,994 396,870 610,864 |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | The results of operations for crude oil and natural gas producing activities are presented below. Year Ended December 31, 2019 2018 2017 (in thousands) Revenue: Crude oil, natural gas and NGLs sales $ 1,307,275 $ 1,389,961 $ 913,084 Commodity price risk management gain (loss), net (162,844 ) 145,237 (3,936 ) 1,144,431 1,535,198 909,148 Expenses: Lease operating expenses 142,248 130,957 89,641 Production taxes 80,754 90,357 60,717 Transportation, gathering and processing expenses 46,353 37,403 33,220 Exploration expense 4,054 6,204 47,334 Depreciation, depletion and amortization 638,499 551,265 462,482 Accretion of asset retirement obligations 6,117 5,075 6,306 Impairment of properties and equipment 38,536 458,397 285,887 (Gain) loss on sale of properties and equipment 9,734 394 (766 ) 966,295 1,280,052 984,821 Results of operations for crude oil and natural gas producing 178,136 255,146 (75,673 ) Income tax (expense) benefit (9,869 ) (185,667 ) 47,247 Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 168,267 $ 69,479 $ (28,426 ) |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2019 2018 2017 (in thousands) Exploratory dry hole costs $ — $ 113 $ 41,297 Geological and geophysical costs, including seismic purchases 3,017 3,401 3,881 Operating, personnel and other 1,037 2,690 2,156 Total exploration, geologic and geophysical expense $ 4,054 $ 6,204 $ 47,334 Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. Year Ended December 31, 2019 2018 2017 (in thousands) Acquisition of properties: (1) Proved properties $ 16,007 $ 205,253 $ 172 Unproved properties 9,567 5,477 18,914 Development costs (2) 780,851 970,970 688,165 Exploration costs: (3) Exploratory drilling 32,218 36,704 80,103 Geological and geophysical 3,017 3,401 3,881 Total costs incurred (4) $ 841,660 $ 1,221,805 $ 791,235 (1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. (2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019 , 2018 and 2017 , $308.9 million , $438.4 million and $463.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $35.3 million , $74.6 million and $32.8 million of infrastructure and pipeline costs in 2019 , 2018 and 2017 respectively. (3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. (4) During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million . We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: As of December 31, 2019 2018 (in thousands) Proved crude oil and natural gas properties $ 6,241,780 $ 5,452,613 Unproved crude oil and natural gas properties 403,379 492,594 Uncompleted wells, equipment and facilities 382,409 332,264 Capitalized costs 7,027,568 6,277,471 Less accumulated DD&A (2,982,929 ) (2,341,897 ) Capitalized costs, net $ 4,044,639 $ 3,935,574 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2019 2018 2017 (in thousands) Future estimated cash flows $ 14,590,604 $ 17,554,880 $ 12,340,407 Future estimated production costs (1) (4,530,173 ) (4,782,948 ) (3,245,627 ) Future estimated development costs (3,257,106 ) (3,632,822 ) (2,893,335 ) Future estimated income tax expense (907,382 ) (1,404,121 ) (748,494 ) Future net cash flows 5,895,943 7,734,989 5,452,951 10% annual discount for estimated timing of cash flows (2,585,609 ) (3,287,273 ) (2,572,846 ) Standardized measure of discounted future estimated net cash flows $ 3,310,334 $ 4,447,716 $ 2,880,105 (1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: Year Ended December 31, 2019 2018 2017 (in thousands) Beginning of period $ 4,447,716 $ 2,880,105 $ 1,420,629 Sales of crude oil, natural gas and NGLs production, net of production costs (1,037,920 ) (1,131,244 ) (729,506 ) Net changes in prices and production costs (1) (2,122,538 ) 936,077 841,713 Extensions, discoveries and improved recovery, less related costs 39,606 190,084 47,240 Sales of reserves (14,533 ) (42,362 ) (2,613 ) Purchases of reserves 18,816 467,807 224,483 Development costs incurred during the period 605,753 462,088 419,047 Revisions of previous quantity estimates 538,242 631,198 484,431 Changes in estimated income taxes 346,826 (232,002 ) (138,560 ) Net changes in future development costs 206,003 (123,663 ) 25,183 Accretion of discount 532,127 583,744 167,487 Timing and other (249,764 ) (174,116 ) 120,571 End of period $ 3,310,334 $ 4,447,716 $ 2,880,105 (1) Our weighted-average price, net of production costs per Boe, in our 2019 reserve report decreased to $16.18 as compared to $23.44 for 2018 and $20.08 for 2017 . |
SUPPLEMENTAL INFORMATION - QU_2
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Document Information [Line Items] | |
Quarterly Financial Information [Table Text Block] | 2019 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 134,500 $ 390,658 $ 365,943 $ 265,022 Total costs, expenses and other 275,120 280,623 321,562 267,713 Income (loss) from operations (140,620 ) 110,035 44,381 (2,691 ) Income (loss) before income taxes (157,588 ) 91,135 26,570 (20,111 ) Net income (loss) $ (120,176 ) $ 68,548 $ 15,908 $ (20,952 ) Earnings per share: Basic $ (1.82 ) $ 1.04 $ 0.25 $ (0.34 ) Diluted (1.82 ) 1.04 0.25 (0.34 ) 2018 Quarter Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) Total revenues $ 260,600 $ 212,531 $ 280,717 $ 794,811 Total costs, expenses and other 260,924 400,770 270,593 538,626 Income (loss) from operations (324 ) (188,239 ) 10,124 256,185 Income (loss) before income taxes (17,705 ) (205,580 ) (7,310 ) 238,024 Net income (loss) $ (13,139 ) $ (160,257 ) $ (3,434 ) $ 178,853 Earnings per share: Basic $ (0.20 ) $ (2.43 ) $ (0.05 ) $ 2.71 Diluted (0.20 ) (2.43 ) (0.05 ) 2.71 |
SCHEDULE II - VALUATION AND Q_2
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |
Summary of Valuation Allowance [Table Text Block] | Description Beginning Charged to Deductions (1) Ending (in thousands) 2019: Allowance for doubtful accounts $ 4,381 $ 3,209 $ 114 $ 7,476 Allowance for expirations of unproved crude oil and natural gas properties 542,709 8,523 544,351 6,881 2018: Allowance for doubtful accounts 3,128 1,276 23 4,381 Allowance for expirations of unproved crude oil and natural gas properties 251,159 388,068 96,518 542,709 2017: Allowance for uncollectible notes $ 44,038 $ — $ 44,038 $ — Allowance for doubtful accounts 2,190 1,108 170 3,128 Allowance for expirations of unproved crude oil and natural gas properties 359 263,817 13,017 251,159 (1) For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. |
Nature of Operations and Basi_2
Nature of Operations and Basis of Presentation Additional Information (Details) | Dec. 31, 2019Wells |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Oil and gas producing wells, gross | 2,649 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies Detail (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Significant Accounting Policies [Line Items] | |||
Cash, cash equivalents and restricted cash, end of year | $ 963 | $ 9,399 | $ 189,925 |
Document Period End Date | Dec. 31, 2019 | ||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 20,100 | 11,300 | |
Non-Oil and gas Depreciation, Depletion and Amortization | 5,700 | 8,500 | 6,600 |
Capitalized Interest | 13,400 | 9,200 | $ 5,000 |
Production Tax Liability | 68,020 | 61,310 | |
Cash and cash equivalents | 963 | 1,398 | |
Restricted Cash | 8,000 | ||
Capitalized Computer Software, Gross | $ 25,900 | $ 1,400 | |
Minimum [Member] | |||
Significant Accounting Policies [Line Items] | |||
Property, Plant and Equipment, Useful Life | 2 years | ||
Maximum [Member] | |||
Significant Accounting Policies [Line Items] | |||
Property, Plant and Equipment, Useful Life | 35 years | ||
Adjustments for New Accounting Pronouncement [Member] | |||
Significant Accounting Policies [Line Items] | |||
Other Accrued Expense | $ 4,600 | ||
Other Liabilities | $ 15,500 |
Acquisition BUSINESS COMBINAT_2
Acquisition BUSINESS COMBINATIONS (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2019 | Apr. 30, 2019 | |
Business Acquisition [Line Items] | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 39,000,000 | ||
Conversion of Stock, Shares Issued | 0.158 | ||
Business Acquisition, Transaction Costs | $ 7.3 | ||
Line of Credit Facility, Initial Borrowing Base | $ 2,100 | 1,600 | |
Revolving Credit Facility Elected Commitment Amount | $ 1,300 | ||
Debt Conversion, Original Debt, Interest Rate of Debt | 101.00% | ||
Stock Repurchase Program, Authorized Amount | $ 525 | $ 200 | |
Subsequent Event [Member] | |||
Business Acquisition [Line Items] | |||
Payments to Acquire Businesses, Gross | 1,700 | ||
Revolving Credit Facility Elected Commitment Amount | 1,700 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt | 165 | ||
Debt Instrument, Repurchased Face Amount | 447.7 | ||
Debt Instrument, Repurchase Amount | 452.2 | ||
Interest Costs Incurred | $ 6.2 |
Acquisition STOCK REPURCHASE PR
Acquisition STOCK REPURCHASE PROGRAM (Details) - USD ($) $ in Millions | Mar. 31, 2020 | Apr. 30, 2019 |
Equity [Abstract] | ||
Stock Repurchase Program, Authorized Amount | $ 525 | $ 200 |
Revenue Recognition Revenue R_3
Revenue Recognition Revenue Recognition Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2017 | |
Revenue Recognition and Deferred Revenue [Abstract] | ||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 20.1 | $ 11.3 |
Revenue Recognition Revenue by
Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue from Contract with Customer, Excluding Assessed Tax | $ 1,307,275 | $ 1,389,961 | $ 913,084 |
Utica Shale [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 4,645 | 22,748 |
Delaware Basin [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 308,025 | 339,265 | 124,684 |
Wattenberg Field | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 999,250 | 1,046,051 | 765,652 |
Crude Oil [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,020,689 | 1,037,961 | 625,053 |
Crude Oil [Member] | Wattenberg Field | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 767,760 | 783,158 | 529,562 |
Crude Oil [Member] | Delaware Basin [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 252,929 | 252,107 | 82,677 |
Crude Oil [Member] | Utica Shale [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 2,696 | 12,814 |
Natural Gas [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 151,020 | 163,192 | 158,259 |
Natural Gas [Member] | Wattenberg Field | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 137,143 | 130,073 | 131,792 |
Natural Gas [Member] | Delaware Basin [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 13,877 | 32,010 | 21,251 |
Natural Gas [Member] | Utica Shale [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 1,109 | 5,216 |
Crude Oil and Natural Gas Liquids (NGL) [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 135,566 | 188,808 | 129,772 |
Crude Oil and Natural Gas Liquids (NGL) [Member] | Wattenberg Field | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 94,347 | 132,820 | 104,298 |
Crude Oil and Natural Gas Liquids (NGL) [Member] | Delaware Basin [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 41,219 | 55,148 | 20,756 |
Crude Oil and Natural Gas Liquids (NGL) [Member] | Utica Shale [Member] | |||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 | $ 840 | $ 4,718 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | $ 31,824 | $ 178,214 |
Liabilities, Fair Value Disclosure | 3,613 | 4,728 |
Net Asset Fair Value | 28,211 | 173,486 |
Fair Value | Significant Other Observable Inputs (Level 2) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 22,886 | 118,521 |
Liabilities, Fair Value Disclosure | 3,089 | 3,364 |
Net Asset Fair Value | 19,797 | 115,157 |
Fair Value | Significant Unobservable Inputs (Level 3) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 8,938 | 59,693 |
Liabilities, Fair Value Disclosure | 524 | 1,364 |
Net Asset Fair Value | 8,414 | 58,329 |
1.125% Convertible Senior Notes due 2021 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notes fair value | $ 188,600 | $ 175,400 |
Notes fair value as percentage of par | 94.30% | 87.70% |
6.125% Senior Notes due 2024 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notes fair value | $ 409,200 | $ 370,200 |
Notes fair value as percentage of par | 102.30% | 92.50% |
5.75% Senior Notes due 2026 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notes fair value | $ 599,400 | $ 532,400 |
Notes fair value as percentage of par | 99.90% | 88.70% |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets [Member] - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value | $ 8,414 | $ 58,329 | $ (9,687) | $ (9,574) |
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item; | (22,694) | 0 | (866) | |
Commodity Price Risk Management, net | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings | (41,749) | 63,257 | 6,241 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements | (8,166) | 4,759 | (6,354) | |
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item; | $ (22,694) | $ 0 | $ (866) |
Concentration of Risk Account_2
Concentration of Risk Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Concentration Risk [Line Items] | ||
Midstream Assets Deferred Payments | $ 81,702 | $ 0 |
Accounts Receivable, Allowance for Credit Loss, Current | (7,476) | (4,381) |
Accounts Receivable, after Allowance for Credit Loss, Current | 266,354 | 181,434 |
Natural gas, NGLs and crude oil sales | ||
Concentration Risk [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 149,758 | 155,756 |
Joint interest billing | ||
Concentration Risk [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 29,510 | 19,580 |
Derivative Counterparties | ||
Concentration Risk [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | 0 | 3,937 |
Other Accounts Receivable | ||
Concentration Risk [Line Items] | ||
Accounts Receivable, before Allowance for Credit Loss | $ 12,860 | $ 6,542 |
Derivative Financial Instrume_3
Derivative Financial Instruments Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | $ 3,613 | $ 4,728 |
Derivative Asset, Fair Value, Gross Asset | 31,824 | 178,214 |
Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Fair Value of Derivatives | 312 | 0 |
Derivative Asset, Fair Value, Gross Asset | 28,078 | 84,492 |
Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 2,921 | 3,364 |
Commodity Contract [Member] | Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Fair Value of Derivatives | 27,766 | 84,492 |
Commodity Contract [Member] | Non Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Fair Value of Derivatives | 3,746 | 93,722 |
Commodity Contract [Member] | Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Fair Value of Derivatives | 529 | 748 |
Commodity Contract [Member] | Non Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 692 | 1,364 |
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Fair Value of Derivatives | $ 2,392 | $ 2,616 |
Concentration of Risk Customer
Concentration of Risk Customer Constituting 10% or more of Total Revenue (Details) | 12 Months Ended | ||
Dec. 31, 2019Rate | Dec. 31, 2018Rate | Dec. 31, 2017Rate | |
Occidental Marketing, Inc. | |||
Concentration Risk [Line Items] | |||
Percentage of Revenue | 20.00% | 0.00% | 0.00% |
DCP Midstream, LP | |||
Concentration Risk [Line Items] | |||
Percentage of Revenue | 17.00% | 12.50% | 19.60% |
Mercuria Energy Trading, Inc. [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Revenue | 16.00% | 0.00% | 0.00% |
United Energy Trading [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of Revenue | 11.00% | 0.00% | 0.00% |
Suncor Energy Marketing, Inc. | |||
Concentration Risk [Line Items] | |||
Percentage of Revenue | 0.00% | 0.00% | 16.40% |
Derivative Financial Instrume_4
Derivative Financial Instruments Impact of Derivative Instruments on Statement of Operations (Details) - Commodity Price Risk Management, net - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative [Line Items] | |||
Net settlements | $ (17,598) | $ (115,538) | $ 13,324 |
Net change in fair value of unsettled derivatives | (145,246) | 260,775 | (17,260) |
Total Derivative Gain (Loss) | $ (162,844) | $ 145,237 | $ (3,936) |
Derivative Financial Instrume_5
Derivative Financial Instruments Effect of Master Netting Agreements (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative [Line Items] | ||
Document Period End Date | Dec. 31, 2019 | |
Derivative Liability | $ 994 | $ 743 |
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 31,824 | 178,214 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (2,619) | (3,985) |
Derivative Asset | 29,205 | 174,229 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 3,613 | 4,728 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | $ (2,619) | $ (3,985) |
Concentration of Risk Notes Rec
Concentration of Risk Notes Receivable (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Accounts Receivable, Credit Loss Expense (Reversal) | $ 0 | $ 0 | $ (40,203) |
Proceeds from Sale of Notes Receivable | $ 40,203 |
Derivative Financial Instrume_6
Derivative Financial Instruments Additional Information (Details) - MBbls | 3 Months Ended | 12 Months Ended |
Mar. 31, 2020 | Dec. 31, 2019 | |
Derivative [Line Items] | ||
Document Period End Date | Dec. 31, 2019 | |
2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | 1,000 | |
2021 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | 2,000 | |
SRC [Domain] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | 3,900 |
Concentration of Risk Other acc
Concentration of Risk Other accrued expenses (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Schedule of Other Accrued Expense [Line Items] | ||
Accrued Employee Benefits, Current | $ 21,611 | $ 25,811 |
Asset Retirement Obligation, Current | 32,200 | 25,598 |
Accrued Environmental Loss Contingencies, Current | 2,256 | 3,038 |
Operating and Finance Lease Liability, Current | 5,926 | 1,779 |
Other Accrued Liabilities | 8,469 | 18,907 |
Other accrued expenses | $ 70,462 | $ 75,133 |
Derivative Financial Instrume_7
Derivative Financial Instruments Outstanding Derivative Contracts (Details) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2020MBbls | Dec. 31, 2019USD ($)MMBTU$ / UnitMBbls | |
Derivative [Line Items] | ||
FV Commodity Derivatives Assets measured with Level 3 | 28.10% | |
Derivative, Fair Value, Net | $ 28,211 | |
FV Commodity Derivatives Liabilities measured with Level 3 | 14.50% | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 75 | |
Natural Gas [Member] | Commodity Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 0 | |
Natural Gas [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 4,014,000 | |
Natural Gas [Member] | Basis Protection Contracts Related to Natural Gas Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ (2,080) | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 24,500,000 | |
Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 30,216 | |
Crude Oil [Member] | Commodity Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 3,600 | |
Crude Oil [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 10,360 | |
2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 1,000 | |
2020 [Member] | Natural Gas [Member] | Dominion South [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 0 | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 14,000 | |
2020 [Member] | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 75 | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 4,000,000 | |
2020 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ (2,392) | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 20,500,000 | |
2020 [Member] | Natural Gas [Member] | Basis Protection - Waha [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 312 | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 4,000,000 | |
2020 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 27,162 | |
2020 [Member] | Crude Oil [Member] | Commodity Option [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 3,600 | |
2020 [Member] | Crude Oil [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 7,160 | |
2021 [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 2,000 | |
2021 [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative, Fair Value, Net | $ 3,054 | |
2021 [Member] | Crude Oil [Member] | Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Volume | MBbls | 3,200 | |
CIG [Member] | Natural Gas [Member] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | (0.62) | |
Dominion South [Member] | Natural Gas [Member] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | 2.54 | |
CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | 2.30 | |
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | 60.98 | |
Derivative, Floor Price | $ / Unit | 55 | |
Derivative, Cap Price | $ / Unit | 71.68 | |
CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member] | 2021 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | 55.76 | |
Waha [Member] | Natural Gas [Member] | 2020 [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / Unit | (1.40) |
Concentration of Risk Other lia
Concentration of Risk Other liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Schedule of Other Liabilities [Line Items] | ||
Amortization of Other Deferred Charges | $ 2,000 | $ 1,400 |
Production Tax Liability | 68,020 | 61,310 |
Deferred Midstream gathering credits | 175,897 | 0 |
Operating and Finance Lease Liability, Noncurrent | 15,779 | 2,900 |
Other Accrued Liabilities | 8,469 | 18,907 |
Other Accrued Liabilities, Noncurrent | 283,133 | 92,664 |
Non Current Liabilities [Member] | ||
Schedule of Other Liabilities [Line Items] | ||
Increase (Decrease) in Accrued Cost of Oil and Gas Reclamation | 20,100 | 22,710 |
Other Accrued Liabilities | 3,337 | $ 5,744 |
Midstream Water Gathering [Member] | ||
Schedule of Other Liabilities [Line Items] | ||
Amortization of Other Deferred Charges | $ 900 | |
Gathering and transport agreement, years | 15 years | |
Long Term Deferred Credit | $ 40,500 | |
Midstream Oil Gathering [Member] | ||
Schedule of Other Liabilities [Line Items] | ||
Amortization of Other Deferred Charges | $ 500 | |
Gathering and transport agreement, years | 15 years | |
Long Term Deferred Credit | $ 28,900 | |
Midstream Gas Gathering [Member] | ||
Schedule of Other Liabilities [Line Items] | ||
Amortization of Other Deferred Charges | $ 2,000 | |
Gathering and transport agreement, years | 22 years | |
Long Term Deferred Credit | $ 110,200 |
Concentration of Risk Customers
Concentration of Risk Customers Constituting Trade Receivable in Excess of 10% (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Concentration Risk [Line Items] | ||
Customers Greater than 10% Trade Receivable | 4 | 3 |
Document Period End Date | Dec. 31, 2019 |
Properties and Equipment Prop_2
Properties and Equipment Properties and Equipment (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)Wells | Dec. 31, 2018USD ($)Wells | Dec. 31, 2017USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Exploratory Wells Drilled, Net Nonproductive | $ 0 | $ 113 | $ 41,297 |
Capitalized Exploratory Well Costs | 16,078 | 12,188 | 15,448 |
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves | 31,901 | 35,127 | |
Properties and equipment, net | 4,095,202 | 4,002,862 | |
Assets | 4,448,680 | 4,544,145 | |
Asset retirement obligations | 95,051 | 85,312 | |
Liabilities | 2,113,173 | 2,017,437 | |
Proved Natural Gas and Crude Oil Properties | 6,241,780 | 5,452,613 | |
Unproved Natural Gas and Crude Oil Properties | 403,379 | 492,594 | |
Total Natural Gas and Crude Oil Properties | 6,645,159 | 5,945,207 | |
Transportation and Other Equipment | 41,888 | 60,612 | |
Land and Buildings | 12,312 | 11,243 | |
Construction in Progress | 408,428 | 356,095 | |
Property and Equipment, at cost | 7,107,787 | 6,373,157 | |
Accumulated Depreciation, Depletion and Amortization | (3,012,585) | (2,370,295) | |
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves | $ (28,011) | $ (38,387) | |
Wells to be completed | Wells | 4 | 2 | |
Geological and geophysical | $ 3,017 | $ 3,401 | 3,881 |
Other expenses | 1,037 | 2,690 | 2,156 |
Exploration, geologic and geophysical expense | 4,054 | 6,204 | 47,334 |
Property, Plant and Equipment, Net | 4,095,202 | 4,002,862 | |
Exploration and Production Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Exploration, geologic and geophysical expense | $ 4,054 | 6,204 | $ 47,334 |
Midstream [Member] [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Assets Held-for-sale, Not Part of Disposal Group, Other | 3,257 | ||
Utica Shale [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Properties and equipment, net | 137,448 | ||
Assets | 140,705 | ||
Asset retirement obligations | 4,111 | ||
Liabilities | $ 4,111 |
Properties and Equipment Impair
Properties and Equipment Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Impairment of natural gas and crude oil properties [Line Items] | |||
Exploratory operating costs | $ 0 | $ 113 | $ 41,297 |
Continuing Operations: | |||
Impairment of proved and unproved properties | 10,599 | 458,397 | 285,465 |
Amortization of Individually Insignificant Unproved Properties | 0 | 0 | 422 |
Impairment of Long-Lived Assets to be Disposed of | 27,937 | 0 | 0 |
Results of Operations, Impairment of Oil and Gas Properties | 38,536 | 458,397 | $ 285,887 |
Delaware Basin Assets [Member] | |||
Continuing Operations: | |||
Impairment of proved and unproved properties | 10,600 | $ 458,400 | |
Discontinued operations: | |||
Impairment of other properties | $ 27,900 |
Properties and Equipment Acreag
Properties and Equipment Acreage Exchange (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Oil and Gas, Acreage [Line Items] | |
Cash Paid for Acreage Acquisition | $ 2.7 |
Loss Recognized on Acreage Exchange | $ 45.6 |
Properties and Equipment Expl_2
Properties and Equipment Exploration (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | |||
Exploratory operating costs | $ 0 | $ 113 | $ 41,297 |
Geological and geophysical | 3,017 | 3,401 | 3,881 |
Other Exploratory costs | 1,037 | 2,690 | 2,156 |
Exploration, geologic and geophysical expense | 4,054 | 6,204 | 47,334 |
Exploration and Production Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Exploration, geologic and geophysical expense | $ 4,054 | $ 6,204 | $ 47,334 |
Properties and Equipment Midstr
Properties and Equipment Midstream Asset Divestiture (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Long Lived Assets Held-for-sale [Line Items] | |||
Exploratory operating costs | $ 0 | $ 113 | $ 41,297 |
Residual Proceeds Allocated to Acreage Dedication Agreements | $ 179,600 | ||
Document Period End Date | Dec. 31, 2019 | ||
Midstream Asset Divestitures [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Proceeds from Sales of Assets, Investing Activities | $ 345,600 | ||
Midstream Water Gathering [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Proceeds from Sales of Assets, Investing Activities | 126,300 | ||
Potential Future Payments on Divestiture of Asset | 56,300 | ||
Gain (Loss) on Disposition of Assets | 25,700 | ||
Midstream Oil Gathering [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Proceeds from Sales of Assets, Investing Activities | 37,300 | ||
Potential Future Payments on Divestiture of Asset | 15,200 | ||
Gain (Loss) on Disposition of Assets | 200 | ||
Midstream Gas Gathering [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Deferred cash payment for divestiture of asset | 82,000 | ||
Proceeds from Sales of Assets, Investing Activities | 182,000 | ||
Cash received for divestiture of asset | 100,000 | ||
Potential Future Payments on Divestiture of Asset | 60,500 | ||
Gain (Loss) on Disposition of Assets | 8,500 | ||
Delaware Basin Assets [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Proceeds from Sales of Assets, Investing Activities | $ 33,400 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Goodwill [Line Items] | |||
Goodwill, Impairment Loss | $ 0 | $ 0 | $ 75,121 |
Leases Lease Cost (Details)
Leases Lease Cost (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Lease, Cost [Abstract] | |
Operating Lease, Cost | $ 4,917 |
Finance Lease, Right-of-Use Asset, Amortization | 1,961 |
Finance Lease, Interest Payment on Liability | 252 |
Finance Lease, Cost | 2,213 |
Short-term Lease, Cost | 170,064 |
Lease, Cost | $ 177,194 |
Leases Leases - Lease Assets an
Leases Leases - Lease Assets and Liabilities (Details) $ in Thousands | Dec. 31, 2019USD ($)Rate |
Assets and Liabilities, Lessee [Abstract] | |
Operating Lease, Right-of-Use Asset | $ 14,926 |
Operating Lease, Liability, Current | 4,159 |
Operating Lease, Liability, Noncurrent | 12,944 |
Operating Lease, Liability | 17,103 |
Finance Lease, Right-of-Use Asset | 4,637 |
Finance Lease, Liability, Current | 1,767 |
Finance Lease, Liability, Noncurrent | 2,835 |
Finance Lease, Liability | $ 4,602 |
Operating Lease, Weighted Average Remaining Lease Term | 4 years 3 months 10 days |
Finance Lease, Weighted Average Remaining Lease Term | 3 years 2 months 1 day |
Operating Lease, Weighted Average Discount Rate, Percent | Rate | 5.00% |
Finance Lease, Weighted Average Discount Rate, Percent | Rate | 5.00% |
Leases Leases - Maturity of Lea
Leases Leases - Maturity of Lease Liabilities Operating (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
2020 | $ 4,847 |
2021 | 4,923 |
2022 | 5,016 |
2023 | 1,559 |
2024 | 950 |
Thereafter | 1,698 |
Total Operating Lease Payments | 18,993 |
Less interest and discount operating, total | (1,890) |
Operating Lease, Liability | $ 17,103 |
Leases Lease - Maturity of Leas
Leases Lease - Maturity of Lease Liabilities Financing (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
2020 | $ 1,949 |
2021 | 1,423 |
2022 | 855 |
2023 | 637 |
2024 | 95 |
Thereafter | 0 |
Total Financing Lease Payments | 4,959 |
Less interest and discount financing, total | (357) |
Finance Lease, Liability | $ 4,602 |
Leases Leases - Maturity of L_2
Leases Leases - Maturity of Lease Liabilities (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Leases [Abstract] | |
2020 | $ 6,796 |
2021 | 6,346 |
2022 | 5,871 |
2023 | 2,196 |
2024 | 1,045 |
Thereafter | 1,698 |
Total Lease Payments | 23,952 |
Less interest and discount, total | (21,705) |
Present value of lease liabilities | $ 2,247 |
Leases Lease Terms (Details)
Leases Lease Terms (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Maximum [Member] | |
Lessee, Lease, Description [Line Items] | |
Operating and Financing Lease Renewal Term | 5 years |
Asset Retirement Obligations _2
Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation Of Changes In Asset Retirement Obligations [Line Items] | |||
Disposal Group, Including Discontinued Operation, Other Liabilities | $ 0 | $ (4,111) | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance beginning of year, January 1 | 115,021 | 87,306 | |
Revisions in estimated cash flows | 28,991 | 30,166 | |
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal | 4,605 | 2,793 | |
Business Acquisition Purchase Price Allocation Asset Retirement Obligation | 2,882 | 4,332 | |
Accretion of asset retirement obligations | 6,117 | 5,075 | $ 6,306 |
Obligations discharged with disposal of properties and asset retirements | (23,426) | (14,651) | |
Balance end of year, December 31 | 127,251 | 115,021 | $ 87,306 |
Less: Current portion | (32,200) | (25,598) | |
Asset Retirement Obligation Liabilities Discharged with Divestiture | $ (6,939) | $ 0 |
Long-Term Debt SCHEDULE OF LONG
Long-Term Debt SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Mar. 31, 2020 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | |||
Document Period End Date | Dec. 31, 2019 | ||
Line of Credit Facility, Initial Borrowing Base | $ 1,600,000 | $ 2,100,000 | |
Total senior notes | 1,173,226 | $ 1,162,376 | |
Total debt, net of discount and unamortized debt issuance costs | 1,177,226 | 1,194,876 | |
Long-term debt | 1,177,226 | 1,194,876 | |
Revolving Credit Facility Elected Commitment Amount | 1,300,000 | ||
1.125% Convertible Senior Notes due 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Principal amount | (200,000) | (200,000) | |
Unamortized Discount | 14,763 | 22,766 | |
Unamortized Debt Issuance Costs | (1,666) | (2,640) | |
Convertible Debt | 183,571 | 174,594 | |
6.125% Senior Notes due 2024 [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized Debt Issuance Costs | (4,611) | (5,590) | |
Principal amount | (400,000) | (400,000) | |
Senior Long Term Notes | 395,389 | 394,410 | |
5.75% Senior Notes due 2026 [Member] | |||
Debt Instrument [Line Items] | |||
Principal amount | (600,000) | (600,000) | |
Unamortized Debt Issuance Costs | (5,734) | (6,628) | |
Convertible Debt | 594,266 | 593,372 | |
Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Revolving credit facility | $ 4,000 | $ 32,500 |
Long-Term Debt ADDITIONAL INFOR
Long-Term Debt ADDITIONAL INFORMATION (Details) - USD ($) | Sep. 15, 2019 | Jun. 30, 2021 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 15, 2021 | Mar. 31, 2020 |
Debt Instrument [Line Items] | |||||||
Redemption of senior notes | $ 0 | $ 0 | $ (519,375,000) | ||||
Loss on extinguishment of debt | $ 0 | 0 | 24,747,000 | ||||
Convertible Note, Conversion Price | $ 85.39 | ||||||
Debt Issuance Costs ($) | $ 72,000 | 7,704,000 | $ 50,000 | ||||
Line of Credit Facility, Initial Borrowing Base | 1,600,000,000 | $ 2,100,000,000 | |||||
Revolving Credit Facility Elected Commitment Amount | 1,300,000,000 | ||||||
Debt Issuance Costs, Line of Credit Arrangements, Net | 8,900,000 | 11,500,000 | |||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,300,000,000 | ||||||
Line of Credit Facility, Weighted Average Interest Rate | 5.00% | ||||||
5.75% Senior Notes due 2026 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | ||||||
Debt Instrument, Redemption, Percentage | 35.00% | ||||||
Minimum percent of aggregate principal debt amount required to remain outstanding | 65.00% | ||||||
6.125% Senior Notes due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | ||||||
1.125% Convertible Senior Notes due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 1.125% | ||||||
Convertible Senior Note, Shares Issued Upon Conversion | 11.7113 | ||||||
5.75% Senior Notes due 2026 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Principal amount | $ 600,000,000 | 600,000,000 | |||||
Debt Issuance Costs, Gross | 7,600,000 | ||||||
Maximum Borrowing Base [Member] | Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Maximum Borrowing Capacity ($) | 2,500,000,000 | ||||||
1.125% Convertible Senior Notes due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Principal amount | 200,000,000 | 200,000,000 | |||||
Debt Issuance Costs, Gross | 4,800,000 | ||||||
Liability component of gross proceeds of Convertible Notes | 160,500,000 | ||||||
Convertible Debt, Equity Component ($) | 39,500,000 | ||||||
6.125% Senior Notes due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Issuance Costs, Gross | 7,800,000 | ||||||
Senior Notes ($) | $ 400,000,000 | $ 400,000,000 | |||||
Forecast [Member] | 1.125% Convertible Senior Notes due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Convertible Note Principal Amount | $ 1,000 | ||||||
Subsequent Event [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Revolving Credit Facility Elected Commitment Amount | $ 1,700,000,000 | ||||||
Subsequent Event [Member] | 1.125% Convertible Senior Notes due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Convertible Note, Conversion Price | $ 85.39 | ||||||
Subsequent Event [Member] | 2026 Senior notes redemption price, after to May 15, 2021 [Member] | 5.75% Senior Notes due 2026 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Redemption Price, Percentage | 104.313% | ||||||
Subsequent Event [Member] | 2026 Senior notes redemption price, prior to May 15, 2021 [Member] | 5.75% Senior Notes due 2026 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Redemption Price, Percentage | 105.75% | ||||||
Subsequent Event [Member] | 2024 Senior notes redemption price, prior to September 15, 2019 [Member] | 6.125% Senior Notes due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Redemption Price, Percentage | 104.594% | ||||||
Restricted Stock [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Share Price | $ 26.17 | $ 29.76 | $ 51.54 | ||||
Unused Commitment Fee [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Interest Rate at Period End | 0.375% | ||||||
Alternate Base Rate Option [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Interest Rate at Period End | 0.25% | ||||||
LIBOR Option [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of Credit Facility, Interest Rate at Period End | 1.25% |
Commitments and Contingencies_2
Commitments and Contingencies Commitments and Contigencies (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019USD ($)MBblsMMcfbbl | Dec. 31, 2017USD ($) | |
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 356,580 | |
Dollar Commitment ($ in thousands) | $ | $ 580,894 | |
LT transportation volumes, net to interest | $ | $ 50,100 | $ 10,000 |
Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 187,675 | |
Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 150,218 | |
Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 18,687 | |
2020 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 75,296 | |
Dollar Commitment ($ in thousands) | $ | $ 85,159 | |
2020 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 30,608 | |
2020 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 37,552 | |
2020 | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,136 | |
2021 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 66,322 | |
Dollar Commitment ($ in thousands) | $ | $ 106,322 | |
2021 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,025 | |
2021 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 28,241 | |
2021 | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 7,056 | |
2022 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 44,645 | |
Dollar Commitment ($ in thousands) | $ | $ 101,107 | |
2022 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,025 | |
2022 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 9,125 | |
2022 | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 4,495 | |
2023 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 40,150 | |
Dollar Commitment ($ in thousands) | $ | $ 85,774 | |
2023 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,025 | |
2023 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 9,125 | |
2023 | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 0 | |
Thereafter | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 130,167 | |
Dollar Commitment ($ in thousands) | $ | $ 202,532 | |
Thereafter | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 63,992 | |
Thereafter | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 66,175 | |
Thereafter | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 0 | |
Supply Contract Expiration Date [Member] | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Aug. 31, 2026 | |
Supply Contract Expiration Date [Member] | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Mar. 31, 2031 | |
Supply Contract Expiration Date [Member] | Appalachiain Basin [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Aug. 31, 2022 | |
Water [Member] | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 31,067 | |
Water [Member] | 2020 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,224 | |
Water [Member] | 2021 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,207 | |
Water [Member] | 2022 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,207 | |
Water [Member] | 2023 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,206 | |
Water [Member] | Thereafter | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 6,223 | |
Water [Member] | Supply Contract Expiration Date [Member] | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Dec. 31, 2024 | |
Crude Oil [Member] | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 92,300 | |
Crude Oil [Member] | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 32,874 | |
Crude Oil [Member] | 2020 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 9,992 | |
Crude Oil [Member] | 2020 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,784 | |
Crude Oil [Member] | 2021 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 16,243 | |
Crude Oil [Member] | 2021 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,030 | |
Crude Oil [Member] | 2022 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 16,243 | |
Crude Oil [Member] | 2022 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,030 | |
Crude Oil [Member] | 2023 | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 12,567 | |
Crude Oil [Member] | 2023 | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 8,030 | |
Crude Oil [Member] | Thereafter | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 37,255 | |
Crude Oil [Member] | Thereafter | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls | 0 | |
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Wattenberg Field [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Dec. 31, 2027 | |
Crude Oil [Member] | Supply Contract Expiration Date [Member] | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Supply Commitments Contract Expiration Date | Dec. 31, 2023 | |
First facilities agreement with midstream provider [Member] | ||
Supply Commitment [Line Items] | ||
incremental volume commitment | 51.5 | |
Second facilities agreement with midstream provider [Member] | ||
Supply Commitment [Line Items] | ||
incremental volume commitment | 33.5 | |
Water [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 31,067 | |
Water [Member] | 2020 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,224 | |
Water [Member] | 2021 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,207 | |
Water [Member] | 2022 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,207 | |
Water [Member] | 2023 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,206 | |
Water [Member] | Thereafter | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 6,223 | |
Crude Oil [Member] | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 125,174 | |
Crude Oil [Member] | 2020 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 18,776 | |
Crude Oil [Member] | 2021 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 24,273 | |
Crude Oil [Member] | 2022 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 24,273 | |
Crude Oil [Member] | 2023 | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 20,597 | |
Crude Oil [Member] | Thereafter | ||
Supply Commitment [Line Items] | ||
Oil and Gas Delivery Commitments Volumes (MMcf) | 37,255 | |
Minimum [Member] | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Committed Barrels of Crude Oil per day | bbl | 22,000 | |
Maximum [Member] | Delaware Basin [Member] | ||
Supply Commitment [Line Items] | ||
Committed Barrels of Crude Oil per day | bbl | 24,000 |
Commitments and Contingencies A
Commitments and Contingencies Additional information (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Oct. 23, 2018 | |
Loss Contingencies [Line Items] | ||||
Transportation, gathering and processing expenses | $ 46,353,000 | $ 37,403,000 | $ 33,220,000 | |
AOC penalty | $ 130,000 | |||
AOC penalty suspended percentage | 20.00% | |||
Delaware Basin/Wattenberg Field [Member] | ||||
Loss Contingencies [Line Items] | ||||
Transportation, gathering and processing expenses | 1,900,000 | |||
Utica Shale natural gas and Wattenberg Field crude oil [Member] | ||||
Loss Contingencies [Line Items] | ||||
Transportation, gathering and processing expenses | $ 1,600,000 |
Commitments and Contingencies L
Commitments and Contingencies Long-term fIrm transportation costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Loss Contingencies [Line Items] | |||
Transportation, gathering and processing expenses | $ 46,353 | $ 37,403 | $ 33,220 |
LT transportation volumes, net to interest | 50,100 | $ 10,000 | |
Utica Shale natural gas and Wattenberg Field crude oil [Member] | |||
Loss Contingencies [Line Items] | |||
Transportation, gathering and processing expenses | $ 1,600 |
Commitments and Contingencies_3
Commitments and Contingencies Commitments and Contingencies New Plant (Details) | 12 Months Ended |
Dec. 31, 2019MMcfbbl | |
Natural Gas [Member] | |
Supply Commitment [Line Items] | |
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments | MMcf | 200 |
Delaware Basin [Member] | Minimum [Member] | |
Supply Commitment [Line Items] | |
Committed Barrels of Crude Oil per day | bbl | 22,000 |
Commitments and Contingencies_4
Commitments and Contingencies Commitments and Contingencies Clean Air Act (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Commitments and Contingencies Clean Air Act [Abstract] | |
Supplemental environmental legal expense paid | $ 1.5 |
Supplemental environment projects legal expense | 1 |
Injunctive relief legal expense accrual | 18 |
Mitigation legal expense accrual | $ 1.7 |
Common Stock Stock based compen
Common Stock Stock based compensation plans (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Mar. 31, 2020 | Apr. 30, 2019 | Dec. 31, 2018 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ||||
Stock Repurchase Program, Authorized Amount | $ 525 | $ 200 | ||
Document Period End Date | Dec. 31, 2019 | |||
Common Stock, Shares Authorized | 150,000,000 | 150,000,000 | ||
Common stock shares remain avaliable for issuance | 133,330 | |||
2018 Equity Incentive Plan [Member] | ||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ||||
Common stock shares remain avaliable for issuance | 1,429,004 |
Common Stock Stocked Based Comp
Common Stock Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Common Stock, Capital Shares Reserved for Future Issuance | 1,800,000 | ||
Stock-based compensation expense | $ 23,837 | $ 21,782 | $ 19,353 |
Income tax benefit | (5,780) | (5,210) | (7,372) |
Net stock-based compensation expense | $ 18,057 | $ 16,572 | $ 11,981 |
Stock Appreciation Rights (SARs) [Member] | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term | 3 years 4 months 24 days |
Common Stock Schedule of Change
Common Stock Schedule of Changes in Stock Option Awards (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Number of Shares | ||||
Outstanding beginning of year, January 1, | 290,258 | 298,220 | 244,078 | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 0 | 0 | 54,142 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 0 | $ 0 | $ 74.57 | |
Shared Based Awards Intrinsic Value | $ 0 | $ 0 | $ 0 | |
Outstanding end of year, December 31, | 290,258 | 290,258 | 298,220 | |
Exercisable at December 31, | 276,775 | 260,101 | 223,865 | |
Weighted-Average Exercise Price | ||||
Outstanding beginning of year, January 1, | $ 46.64 | $ 47.39 | $ 41.36 | |
Outstanding end of year, December 31, | 46.64 | 46.64 | 47.39 | |
Exercisable at December 31, | $ 45.28 | $ 44.88 | $ 43.28 | |
Weighted-Average Remaining Contractual Term (in years) | ||||
Outstanding at December 31, | 3 years 7 months 6 days | 4 years 7 months 6 days | ||
Exercisable at December 31, | 3 years 4 months 24 days | |||
Aggregate Intrinsic Value (in thousands) | ||||
Outstanding at December 31 | $ 41 | $ 125 | $ 2,490 | $ 7,620 |
Common Stock SARs Fair Value As
Common Stock SARs Fair Value Assumptions (Details) | 12 Months Ended |
Dec. 31, 2017$ / sharesRate | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Expected term of award | 6 years |
Risk-free interest rate | 2.00% |
Expected Volatility | 53.30% |
Weighted-average grant date fair value per share | $ / shares | $ 38.58 |
Common Stock Schedule of Chan_2
Common Stock Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) | 12 Months Ended | ||||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Number of SARs | |||||||
Outstanding beginning of year, January 1, | 290,258 | 298,220 | 244,078 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | 0 | 0 | 54,142 | ||||
Outstanding end of year, December 31, | 290,258 | 290,258 | 298,220 | ||||
Exercisable at December 31, | 276,775 | 260,101 | 223,865 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 0 | $ 0 | $ 74.57 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |||||||
Outstanding beginning of year, January 1, | $ 46.64 | $ 47.39 | $ 41.36 | ||||
Outstanding end of year, December 31, | $ 46.64 | $ 46.64 | $ 47.39 | ||||
Exercisable at December 31, | $ 45.28 | $ 44.88 | $ 43.28 | ||||
Weighted-Average Remaining Contractual Term (in years) | |||||||
Outstanding at December 31, | 3 years 7 months 6 days | 4 years 7 months 6 days | |||||
Exercisable at December 31, | 3 years 4 months 24 days | ||||||
Share based compesation aggregate intrinsic valu [Roll Forward] | |||||||
Outstanding beginning of year, January 1, | $ 41,000 | $ 125,000 | $ 2,490,000 | $ 41,000 | $ 125,000 | $ 2,490,000 | $ 7,620,000 |
Shared Based Awards Intrinsic Value | 0 | 0 | 0 | ||||
Outstanding end of year, December 31, | $ 41,000 | $ 125,000 | $ 2,490,000 | ||||
Exercisable at December 31, | 41,000 | 125,000 | 2,267,000 | ||||
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent | $ 0 | $ 63,969 | $ 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 0 | $ 42.83 | $ 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period | 0 | (71,931) | 0 | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ 0 | $ 46.34 | $ 0 |
Common Stock Schedule of Chan_3
Common Stock Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Weighted-Average Grant-Date Fair Value | |||
Weighted-average grant date fair value per share | $ 38.58 | ||
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed | ||
Number of Shares | |||
Outstanding beginning of year, January 1, | 618,407 | ||
Granted | 588,899 | ||
Vested | (307,450) | ||
Forfeited | (103,930) | ||
Outstanding end of year, December 31, | 795,926 | 618,407 | |
Weighted-Average Grant-Date Fair Value | |||
Outstanding at beginning of year, January 1, | $ 54.16 | ||
Weighted-average grant date fair value per share | 40.34 | $ 50.69 | $ 65.14 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | 52.98 | ||
Forfeited | 45.62 | ||
Outstanding at end of year, December 31, | $ 45.51 | $ 54.16 | |
Total intrinsic value of time based awards vested | $ 11,652 | $ 12,282 | $ 16,303 |
Total intrinsic value of time-based awards non-vested | $ 20,829 | $ 18,404 | $ 24,334 |
Market price per common share as of December 31, | $ 26.17 | $ 29.76 | $ 51.54 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 21,400 | ||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition | 1 year 8 months 12 days |
Common Stock Restricted Stock -
Common Stock Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term of award | 6 years | ||
Risk-free interest rate | 2.00% | ||
Expected Volatility | 53.30% | ||
Weighted-average grant date fair value per share | $ 38.58 | ||
Restricted Stock - Market Based Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition | 1 year 7 months 6 days | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value | $ 530 | $ 620 | $ 2,687 |
Expected term of award | 3 years | 3 years | 3 years |
Risk-free interest rate | 2.50% | 2.40% | 1.40% |
Expected Volatility | 41.40% | 42.30% | 51.40% |
Weighted-average grant date fair value per share | $ 56.68 | $ 69.98 | $ 94.02 |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved | ||
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Shares Payout Range | 0.00% | ||
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Shares Payout Range | 200.00% |
Common Stock Schedule of Chan_4
Common Stock Schedule of Changes in Restricted Stock - Market Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Weighted-Average Grant-Date Fair Value | |||
Weighted-average grant date fair value per share | $ 38.58 | ||
Restricted Stock - Market Based Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value | $ 530 | $ 620 | $ 2,687 |
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award | The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved | ||
Time based shares granted to executives | 139,197 | ||
Number of Shares | |||
Outstanding beginning of year, January 1, | 102,914 | ||
Granted | 139,197 | ||
Vested | (20,969) | ||
Forfeited | 0 | ||
Outstanding end of year, December 31, | 221,142 | 102,914 | |
Weighted-Average Grant-Date Fair Value | |||
Outstanding at beginning of year, January 1, | $ 74.88 | ||
Weighted-average grant date fair value per share | 56.68 | $ 69.98 | $ 94.02 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | 94.02 | ||
Forfeited | 0 | ||
Outstanding at end of year, December 31, | $ 61.61 | $ 74.88 | |
Total intrinsic value of market-based awards non-vested | $ 5,787 | $ 3,063 | $ 2,698 |
Market price per common share as of December 31, | $ 26.17 | $ 29.76 | $ 51.54 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 7,500 | ||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition | 1 year 7 months 6 days |
Common Stock Preferred Stock (D
Common Stock Preferred Stock (Details) - shares | Dec. 31, 2019 | Dec. 31, 2018 | Jun. 23, 2008 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Preferred Stock, Shares Authorized | 50,000,000 | 50,000,000 | |
Preferred Stock, Shares Issued | 0 | 0 | |
Preferred Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Preferred Stock, Shares Authorized | 50,000,000 | ||
Preferred Stock, Shares Issued | 0 |
Common Stock Stock Repurchase (
Common Stock Stock Repurchase (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Apr. 30, 2019 | |
Equity, Class of Treasury Stock [Line Items] | |||||
Stock Repurchase Program, Authorized Amount | $ 525,000 | $ 200,000 | |||
Payments for Repurchase of Common Stock | $ 4,003 | $ 5,147 | $ 6,672 | ||
Treasury Stock, Common [Member] | |||||
Equity, Class of Treasury Stock [Line Items] | |||||
Stock Repurchased During Period, Shares | (4,706,139) | ||||
Payments for Repurchase of Common Stock | $ 154,400 | ||||
Subsequent Event [Member] | Treasury Stock, Common [Member] | |||||
Equity, Class of Treasury Stock [Line Items] | |||||
Stock Repurchased During Period, Shares | (600,000) | ||||
Payments for Repurchase of Common Stock | $ 12,500 |
Income Taxes Provision for Inco
Income Taxes Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Current Federal Tax Benefit (Expense) | $ 1,366 | $ 887 | $ 8,443 |
Current State and Local Tax Benefit (Expense) | (300) | (188) | (200) |
Current Income Tax Expense (Benefit) | 1,066 | 699 | 8,243 |
Deferred Federal Income Tax Benefit (Expense) | 4,507 | (1,986) | 193,809 |
Deferred State and Local Income Tax Benefit (Expense) | (2,251) | (4,119) | 9,876 |
Deferred Income Tax from Continuing Operations | 2,256 | (6,105) | 203,685 |
Income tax (expense) benefit | $ 3,322 | $ (5,406) | $ 211,928 |
Income Taxes Reconciliation of
Income Taxes Reconciliation of Statutory Rate to Effective Rate (Details) | 12 Months Ended | ||
Dec. 31, 2019Rate | Dec. 31, 2018Rate | Dec. 31, 2017Rate | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||
Statutory tax rate | 21.00% | 21.00% | 35.00% |
State income tax, net | 3.60% | (6.40%) | 1.80% |
Federal tax credits | (3.30%) | (52.10%) | 0.00% |
Effect of state income tax rate changes | (6.40%) | 6.70% | 0.00% |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | (0.60%) | 45.50% | 0.00% |
Non-deductible compensation | (5.00%) | 21.80% | (0.30%) |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion, Percent | (2.30%) | 0.00% | 0.00% |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Amount | (1.00%) | 31.80% | 0.00% |
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent | (0.50%) | 4.90% | 0.00% |
Federal tax reform rate reduction | 0.00% | 0.00% | 33.70% |
Non-deductible goodwill impairment | 0.00% | 0.00% | (7.70%) |
Other | 0.00% | (0.40%) | (0.10%) |
Effective Income Tax Rate Reconciliation, Percent | 5.50% | 72.80% | 62.40% |
Income Taxes Tax Effects of Tem
Income Taxes Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Components of Deferred Tax Assets [Abstract] | ||
Deferred compensation | $ 9,905 | $ 9,963 |
Asset retirement obligations | 30,993 | 27,166 |
deferred tax assets, federal tax | 22,965 | 54,736 |
State NOL and tax credit carryforwards, net | 9,508 | 13,223 |
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax | 4,448 | 7,756 |
Deferred Tax Assets, Tax Deferred Expense, Other | 4,874 | 5,288 |
Other | 3,887 | 4,647 |
Deferred Tax Assets, Valuation Allowance, Current | (3,775) | 3,380 |
Deferred tax assets | 82,805 | 119,399 |
Components of Deferred Tax Liabilities [Abstract] | ||
properties and equipment | 268,234 | 270,565 |
Deferred Tax Liabilities, Derivatives | 6,841 | 41,496 |
Convertible debt | 3,571 | 5,434 |
Total gross deferred tax liabilities | 278,646 | 317,495 |
Net deferred tax liability | $ 195,841 | $ 198,096 |
Income Taxes Additional Informa
Income Taxes Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards: | |||
Document Period End Date | Dec. 31, 2019 | ||
Deferred Tax Liabilities, Property, Plant and Equipment | $ 268,234 | $ 270,565 | |
Federal tax reform rate reduction | 0.00% | 0.00% | 33.70% |
Effective Income Tax Rate Reconciliation, Percent | 5.50% | 72.80% | 62.40% |
Net deferred tax liability | $ 195,841 | $ 198,096 | |
Income Tax Expense (Benefit) | (2,256) | 6,105 | $ (203,685) |
Deferred tax asset, operating loss carryforward, annual limitation | 15,100 | ||
Operating loss carryforward utilization | 126,400 | ||
Operating Loss Carryforwards | 175,700 | ||
Alternative minimum tax - credit carryforward | 4,448 | $ 7,756 | |
State operating loss carryforward utilization | 98,000 | ||
State NOL Carryforwards | |||
Operating Loss Carryforwards: | |||
State NOL carryforwards | 265,900 | ||
State Credit Carryforwards | |||
Operating Loss Carryforwards: | |||
State credit carryforwards | 4,000 | ||
Delaware Basin Acquisition [Member] | |||
Operating Loss Carryforwards: | |||
Deferred Tax Assets, Operating Loss Carryforwards | 60,100 | ||
2036 [Member] | |||
Operating Loss Carryforwards: | |||
Operating Loss Carryforwards | $ 31,500 |
Earnings per share Earnings Per
Earnings per share Earnings Per Share (Details) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of Weighted-Average Diluted Shares Outstanding | |||
Weighted average common shares outstanding - basic | 64,032 | 66,059 | 65,837 |
Weighted Average Number of Shares Outstanding - Diluted | 64,032 | 66,303 | 65,837 |
Anti-dilutive Effect | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 1,291 | 254 | 665 |
Convertible Senior Note | |||
Convertible Note, Number of Shares Convertible | 2,300 | ||
Convertible Note, Conversion Price | $ 85.39 | ||
Restricted Stock [Member] | |||
Reconciliation of Weighted-Average Diluted Shares Outstanding | |||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 0 | 173 | 0 |
Anti-dilutive Effect | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 989 | 145 | 590 |
Other Equity-Based Awards | |||
Reconciliation of Weighted-Average Diluted Shares Outstanding | |||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 0 | 71 | 0 |
Anti-dilutive Effect | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 302 | 109 | 75 |
Supplemental Cash Flow Supple_3
Supplemental Cash Flow Supplemental Cash Flow (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Line Items] | |||
Interest Paid, Excluding Capitalized Interest, Operating Activities | $ 57,439 | $ 55,586 | $ 69,880 |
Income Taxes Paid, Net | (1,167) | (6,719) | (13,925) |
Capital Expenditures Incurred but Not yet Paid | (68,246) | 36,328 | 50,761 |
Noncash Change In Asset Retirement Obligation | 29,533 | 37,136 | 839 |
Operating Lease, Payments | 5,301 | ||
Operating Cash Flow from Financing Leases | 253 | ||
Finance Lease, Principal Payments | 1,952 | 1,495 | 1,168 |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 1,428 | ||
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability | $ 2,323 | ||
Not Restated [Domain] | |||
Supplemental Cash Flow Elements [Line Items] | |||
Operating Lease, Payments | 0 | 0 | |
Operating Cash Flow from Financing Leases | 0 | 0 | |
Finance Lease, Principal Payments | 0 | 0 | |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 0 | 0 | |
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability | $ 0 | $ 0 |
Subsidiary Guarantor SUBSIDIA_3
Subsidiary Guarantor SUBSIDIARY GUARANTOR BALANCE SHEET (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Cash and cash equivalents | $ 963,000 | $ 1,398,000 |
Accounts receivable, net | 266,354,000 | 181,434,000 |
Fair value of derivatives | 28,078,000 | 84,492,000 |
Prepaid expenses and other current assets | 8,635,000 | 7,136,000 |
Assets, Current | 304,030,000 | 274,460,000 |
Properties and equipment, net | 4,095,202,000 | 4,002,862,000 |
Assets held-for-sale, net | 0 | 140,705,000 |
Intercompany Receivables | 0 | 0 |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 0 | 0 |
Fair value of derivatives | 3,746,000 | 93,722,000 |
Other assets | 45,702,000 | 32,396,000 |
Assets | 4,448,680,000 | 4,544,145,000 |
Accounts payable | 98,934,000 | 181,864,000 |
Production tax liability | 76,236,000 | 60,719,000 |
Fair value of derivatives | 2,921,000 | 3,364,000 |
Funds held for distribution | 98,393,000 | 105,784,000 |
Accrued interest payable | 14,284,000 | 14,150,000 |
Other accrued expenses | 70,462,000 | 75,133,000 |
Liabilities, Current | 361,230,000 | 441,014,000 |
Intercompany Payable | 0 | 0 |
Long-term debt | 1,177,226,000 | 1,194,876,000 |
Deferred income taxes | 195,841,000 | 198,096,000 |
Asset retirement obligations | 95,051,000 | 85,312,000 |
Disposal Group, Including Discontinued Operation, Liabilities | 0 | 4,111,000 |
Fair value of derivatives | 692,000 | 1,364,000 |
Other liabilities | 283,133,000 | 92,664,000 |
Liabilities | 2,113,173,000 | 2,017,437,000 |
Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 617,000 | 661,000 |
Additional paid-in capital | 2,384,309,000 | 2,519,423,000 |
Retained earnings (deficit) | (47,945,000) | 8,727,000 |
Treasury Stock, Value | 1,474,000 | 2,103,000 |
Stockholders' Equity Attributable to Parent | 2,335,507,000 | 2,526,708,000 |
Liabilities and Equity | 4,448,680,000 | 4,544,145,000 |
Corporate, Non-Segment [Member] | ||
Cash and cash equivalents | 963,000 | 1,398,000 |
Accounts receivable, net | 140,742,000 | 146,529,000 |
Fair value of derivatives | 28,078,000 | 84,492,000 |
Prepaid expenses and other current assets | 8,204,000 | 6,725,000 |
Assets, Current | 177,987,000 | 239,144,000 |
Properties and equipment, net | 2,328,337,000 | 2,270,711,000 |
Assets held-for-sale, net | 0 | |
Intercompany Receivables | 348,818,000 | 451,601,000 |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 1,286,931,000 | 1,316,945,000 |
Fair value of derivatives | 3,746,000 | 93,722,000 |
Other assets | 38,863,000 | 30,084,000 |
Assets | 4,184,682,000 | 4,402,207,000 |
Accounts payable | 72,212,000 | 110,847,000 |
Production tax liability | 67,509,000 | 53,309,000 |
Fair value of derivatives | 2,921,000 | 3,364,000 |
Funds held for distribution | 83,072,000 | 90,183,000 |
Accrued interest payable | 14,281,000 | 14,143,000 |
Other accrued expenses | 68,803,000 | 73,689,000 |
Liabilities, Current | 308,798,000 | 345,535,000 |
Intercompany Payable | 0 | 0 |
Long-term debt | 1,177,226,000 | 1,194,876,000 |
Deferred income taxes | 169,520,000 | 162,368,000 |
Asset retirement obligations | 87,749,000 | 79,904,000 |
Disposal Group, Including Discontinued Operation, Liabilities | 0 | |
Fair value of derivatives | 692,000 | 1,364,000 |
Other liabilities | 105,190,000 | 91,452,000 |
Liabilities | 1,849,175,000 | 1,875,499,000 |
Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 617,000 | 661,000 |
Additional paid-in capital | 2,384,309,000 | 2,519,423,000 |
Retained earnings (deficit) | (47,945,000) | 8,727,000 |
Treasury Stock, Value | 1,474,000 | 2,103,000 |
Stockholders' Equity Attributable to Parent | 2,335,507,000 | 2,526,708,000 |
Liabilities and Equity | 4,184,682,000 | 4,402,207,000 |
Reportable Legal Entities [Member] | ||
Cash and cash equivalents | 0 | 0 |
Accounts receivable, net | 125,612,000 | 34,905,000 |
Fair value of derivatives | 0 | 0 |
Prepaid expenses and other current assets | 431,000 | 411,000 |
Assets, Current | 126,043,000 | 35,316,000 |
Properties and equipment, net | 1,766,865,000 | 1,732,151,000 |
Assets held-for-sale, net | 140,705,000 | |
Intercompany Receivables | 0 | 0 |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | 0 | 0 |
Fair value of derivatives | 0 | 0 |
Other assets | 6,839,000 | 2,312,000 |
Assets | 1,899,747,000 | 1,910,484,000 |
Accounts payable | 26,722,000 | 71,017,000 |
Production tax liability | 8,727,000 | 7,410,000 |
Fair value of derivatives | 0 | 0 |
Funds held for distribution | 15,321,000 | 15,601,000 |
Accrued interest payable | 3,000 | 7,000 |
Other accrued expenses | 1,659,000 | 1,444,000 |
Liabilities, Current | 52,432,000 | 95,479,000 |
Intercompany Payable | 348,818,000 | 451,601,000 |
Long-term debt | 0 | 0 |
Deferred income taxes | 26,321,000 | 35,728,000 |
Asset retirement obligations | 7,302,000 | 5,408,000 |
Disposal Group, Including Discontinued Operation, Liabilities | 4,111,000 | |
Fair value of derivatives | 0 | 0 |
Other liabilities | 177,943,000 | 1,212,000 |
Liabilities | 612,816,000 | 593,539,000 |
Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 0 | 0 |
Additional paid-in capital | 1,766,775,000 | 1,766,775,000 |
Retained earnings (deficit) | (479,844,000) | (449,830,000) |
Treasury Stock, Value | 0 | 0 |
Stockholders' Equity Attributable to Parent | 1,286,931,000 | 1,316,945,000 |
Liabilities and Equity | 1,899,747,000 | 1,910,484,000 |
Consolidation, Eliminations [Member] | ||
Cash and cash equivalents | 0 | 0 |
Accounts receivable, net | 0 | 0 |
Fair value of derivatives | 0 | 0 |
Prepaid expenses and other current assets | 0 | 0 |
Assets, Current | 0 | 0 |
Properties and equipment, net | 0 | 0 |
Assets held-for-sale, net | 0 | |
Intercompany Receivables | (348,818,000) | (451,601,000) |
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure | (1,286,931,000) | (1,316,945,000) |
Fair value of derivatives | 0 | 0 |
Other assets | 0 | 0 |
Assets | (1,635,749,000) | (1,768,546,000) |
Accounts payable | 0 | 0 |
Production tax liability | 0 | 0 |
Fair value of derivatives | 0 | 0 |
Funds held for distribution | 0 | 0 |
Accrued interest payable | 0 | 0 |
Other accrued expenses | 0 | 0 |
Liabilities, Current | 0 | 0 |
Intercompany Payable | (348,818,000) | (451,601,000) |
Long-term debt | 0 | 0 |
Deferred income taxes | 0 | 0 |
Asset retirement obligations | 0 | 0 |
Disposal Group, Including Discontinued Operation, Liabilities | 0 | |
Fair value of derivatives | 0 | 0 |
Other liabilities | 0 | 0 |
Liabilities | (348,818,000) | (451,601,000) |
Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 0 | 0 |
Additional paid-in capital | (1,766,775,000) | (1,766,775,000) |
Retained earnings (deficit) | 479,844,000 | 449,830,000 |
Treasury Stock, Value | 0 | 0 |
Stockholders' Equity Attributable to Parent | (1,286,931,000) | (1,316,945,000) |
Liabilities and Equity | $ (1,635,749,000) | $ (1,768,546,000) |
Subsidiary Guarantor SUBSIDIA_4
Subsidiary Guarantor SUBSIDIARY GUARANTOR INCOME STATEMENT (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Results of Operations, Revenue from Oil and Gas Producing Activities | $ 1,307,275 | $ 1,389,961 | $ 913,084 | ||||||||
Commodity price risk management gain (loss), net | (162,844) | 145,237 | (3,936) | ||||||||
Other income | 11,692 | 13,461 | 12,468 | ||||||||
Revenues | $ 265,022 | $ 365,943 | $ 390,658 | $ 134,500 | $ 794,811 | $ 280,717 | $ 212,531 | $ 260,600 | 1,156,123 | 1,548,659 | 921,616 |
Lease operating expenses | 142,248 | 130,957 | 89,641 | ||||||||
Production taxes | 80,754 | 90,357 | 60,717 | ||||||||
Transportation, gathering and processing expenses | 46,353 | 37,403 | 33,220 | ||||||||
Exploration, geologic and geophysical expense | 4,054 | 6,204 | 47,334 | ||||||||
Impairment of properties and equipment | 38,536 | 458,397 | 285,887 | ||||||||
Impairment of goodwill | 0 | 0 | 75,121 | ||||||||
General and administrative expense | 161,753 | 170,504 | 120,370 | ||||||||
Depreciation, depletion and amortization | 644,152 | 559,793 | 469,084 | ||||||||
Accretion of asset retirement obligations | 6,117 | 5,075 | 6,306 | ||||||||
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | (9,734) | (394) | 766 | ||||||||
Accounts Receivable, Credit Loss Expense (Reversal) | 0 | 0 | (40,203) | ||||||||
Other expenses | 11,317 | 11,829 | 13,157 | ||||||||
Total cost, expenses and other | 267,713 | 321,562 | 280,623 | 275,120 | 538,626 | 270,593 | 400,770 | 260,924 | 1,145,018 | 1,470,913 | 1,159,868 |
Operating Income (Loss) | (2,691) | 44,381 | 110,035 | (140,620) | 256,185 | 10,124 | (188,239) | (324) | 11,105 | 77,746 | (238,252) |
Gain (Loss) on Extinguishment of Debt | 0 | 0 | (24,747) | ||||||||
Interest Expense | 71,171 | 70,730 | 78,694 | ||||||||
Interest income | 72 | 413 | 2,261 | ||||||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (20,111) | 26,570 | 91,135 | (157,588) | 238,024 | (7,310) | (205,580) | (17,705) | (59,994) | 7,429 | (339,432) |
Income Tax Expense (Benefit) | (3,322) | 5,406 | (211,928) | ||||||||
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | 0 | ||||||||
Net income (loss) | $ (20,952) | $ 15,908 | $ 68,548 | $ (120,176) | $ 178,853 | $ (3,434) | $ (160,257) | $ (13,139) | (56,672) | 2,023 | (127,504) |
Reportable Legal Entities [Member] | |||||||||||
Results of Operations, Revenue from Oil and Gas Producing Activities | 308,025 | 339,265 | 124,684 | ||||||||
Commodity price risk management gain (loss), net | 0 | 0 | 0 | ||||||||
Other income | 720 | 2,717 | 567 | ||||||||
Revenues | 308,745 | 341,982 | 125,251 | ||||||||
Lease operating expenses | 47,419 | 38,729 | 21,610 | ||||||||
Production taxes | 19,177 | 22,538 | 7,481 | ||||||||
Transportation, gathering and processing expenses | 22,634 | 20,796 | 9,919 | ||||||||
Exploration, geologic and geophysical expense | 2,943 | 4,970 | 46,242 | ||||||||
Impairment of properties and equipment | 38,244 | 458,370 | 280,936 | ||||||||
Impairment of goodwill | 75,121 | ||||||||||
General and administrative expense | 17,408 | 17,706 | 12,852 | ||||||||
Depreciation, depletion and amortization | 192,870 | 169,952 | 65,100 | ||||||||
Accretion of asset retirement obligations | 671 | 458 | 341 | ||||||||
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | (10,587) | (4,781) | 0 | ||||||||
Accounts Receivable, Credit Loss Expense (Reversal) | 0 | ||||||||||
Other expenses | 0 | 0 | 0 | ||||||||
Total cost, expenses and other | 351,953 | 738,300 | 519,602 | ||||||||
Operating Income (Loss) | (43,208) | (396,318) | (394,351) | ||||||||
Gain (Loss) on Extinguishment of Debt | 0 | ||||||||||
Interest Expense | 4,086 | 2,521 | 1,225 | ||||||||
Interest income | 1 | 0 | 0 | ||||||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (39,121) | (393,797) | (393,126) | ||||||||
Income Tax Expense (Benefit) | (9,106) | (93,205) | (245,571) | ||||||||
Income (Loss) from Subsidiaries, Net of Tax | 0 | 0 | 0 | ||||||||
Net income (loss) | (30,015) | (300,592) | (147,555) | ||||||||
Corporate, Non-Segment [Member] | |||||||||||
Results of Operations, Revenue from Oil and Gas Producing Activities | 999,250 | 1,050,696 | 788,400 | ||||||||
Commodity price risk management gain (loss), net | (162,844) | 145,237 | (3,936) | ||||||||
Other income | 10,972 | 10,744 | 11,901 | ||||||||
Revenues | 847,378 | 1,206,677 | 796,365 | ||||||||
Lease operating expenses | 94,829 | 92,228 | 68,031 | ||||||||
Production taxes | 61,577 | 67,819 | 53,236 | ||||||||
Transportation, gathering and processing expenses | 23,719 | 16,607 | 23,301 | ||||||||
Exploration, geologic and geophysical expense | 1,111 | 1,234 | 1,092 | ||||||||
Impairment of properties and equipment | 292 | 27 | 4,951 | ||||||||
Impairment of goodwill | 0 | ||||||||||
General and administrative expense | 144,345 | 152,798 | 107,518 | ||||||||
Depreciation, depletion and amortization | 451,282 | 389,841 | 403,984 | ||||||||
Accretion of asset retirement obligations | 5,446 | 4,617 | 5,965 | ||||||||
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | 853 | 4,387 | 766 | ||||||||
Accounts Receivable, Credit Loss Expense (Reversal) | (40,203) | ||||||||||
Other expenses | 11,317 | 11,829 | 13,157 | ||||||||
Total cost, expenses and other | 793,065 | 732,613 | 640,266 | ||||||||
Operating Income (Loss) | 54,313 | 474,064 | 156,099 | ||||||||
Gain (Loss) on Extinguishment of Debt | (24,747) | ||||||||||
Interest Expense | 75,257 | 73,251 | 79,919 | ||||||||
Interest income | 71 | 413 | 2,261 | ||||||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (20,873) | 401,226 | 53,694 | ||||||||
Income Tax Expense (Benefit) | 5,784 | 98,611 | 33,643 | ||||||||
Income (Loss) from Subsidiaries, Net of Tax | (30,015) | (300,592) | (147,555) | ||||||||
Net income (loss) | (56,672) | 2,023 | (127,504) | ||||||||
Consolidation, Eliminations [Member] | |||||||||||
Results of Operations, Revenue from Oil and Gas Producing Activities | 0 | 0 | 0 | ||||||||
Commodity price risk management gain (loss), net | 0 | 0 | 0 | ||||||||
Other income | 0 | 0 | 0 | ||||||||
Revenues | 0 | 0 | 0 | ||||||||
Lease operating expenses | 0 | 0 | 0 | ||||||||
Production taxes | 0 | 0 | 0 | ||||||||
Transportation, gathering and processing expenses | 0 | 0 | 0 | ||||||||
Exploration, geologic and geophysical expense | 0 | 0 | 0 | ||||||||
Impairment of properties and equipment | 0 | 0 | 0 | ||||||||
Impairment of goodwill | 0 | ||||||||||
General and administrative expense | 0 | 0 | 0 | ||||||||
Depreciation, depletion and amortization | 0 | 0 | 0 | ||||||||
Accretion of asset retirement obligations | 0 | 0 | 0 | ||||||||
GainLossonSaleOfOilAndGasPropertyFromContinuingOperations | 0 | 0 | 0 | ||||||||
Accounts Receivable, Credit Loss Expense (Reversal) | 0 | ||||||||||
Other expenses | 0 | 0 | 0 | ||||||||
Total cost, expenses and other | 0 | 0 | 0 | ||||||||
Operating Income (Loss) | 0 | 0 | 0 | ||||||||
Gain (Loss) on Extinguishment of Debt | 0 | ||||||||||
Interest Expense | 0 | 0 | 0 | ||||||||
Interest income | 0 | 0 | 0 | ||||||||
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | 0 | 0 | 0 | ||||||||
Income Tax Expense (Benefit) | 0 | 0 | 0 | ||||||||
Income (Loss) from Subsidiaries, Net of Tax | 30,015 | 300,592 | 147,555 | ||||||||
Net income (loss) | $ 30,015 | $ 300,592 | $ 147,555 |
Subsidiary Guarantor SUBSIDIA_5
Subsidiary Guarantor SUBSIDIARY GUARANTOR CASH FLOWS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net Cash Provided by (Used in) Operating Activities | $ 858,226 | $ 889,302 | $ 597,813 |
Capital expenditures for development of crude oil and natural gas properties | (855,908) | (946,350) | (737,208) |
Capital expenditures for other properties and equipment | (20,839) | (11,055) | (5,094) |
Acquisition of crude oil and natural gas properties | (13,207) | (180,026) | (15,628) |
Proceeds from sale of properties and equipment | (2,105) | (3,562) | (9,991) |
Proceeds from divestitures | 202,076 | 44,693 | 0 |
Proceeds from Sale of Notes Receivable | 40,203 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | (9,250) | ||
Restricted cash | 8,001 | 1,249 | (9,250) |
Sale of short-term investments | 0 | 0 | 49,890 |
Purchase of short-term investments | 0 | 0 | (49,890) |
intercompany Transfer Investing Activities | 0 | 0 | 0 |
Net Cash Provided by (Used in) Investing Activities | (677,772) | (1,087,927) | (716,986) |
Proceeds from issuance of senior notes | 0 | 0 | 592,366 |
Redemption of convertible notes | (519,375) | ||
Redemption of senior notes | 0 | 0 | (519,375) |
Proceeds from Lines of Credit | 1,577,000 | 1,072,500 | |
Repayment of revolving credit facility | (1,605,500) | (1,040,000) | 0 |
Payment of debt issuance costs | (72) | (7,704) | (50) |
Treasury Stock, Value, Acquired, Cost Method | (154,363) | (5,147) | (6,672) |
Purchase of treasury shares | (4,003) | (5,147) | (6,672) |
Finance Lease, Principal Payments | (1,952) | (1,495) | (1,168) |
Other | 0 | (55) | (103) |
Intercompany Transfers Financing Activities | 0 | 0 | 0 |
Net Cash Provided by (Used in) Financing Activities | (188,890) | 18,099 | 64,998 |
Net change in cash, cash equivalents and restricted cash | (8,436) | (180,526) | (54,175) |
Cash, cash equivalents and restricted cash, beginning of year | 9,399 | 189,925 | 244,100 |
Cash, cash equivalents and restricted cash, end of year | 963 | 9,399 | 189,925 |
Corporate, Non-Segment [Member] | |||
Net Cash Provided by (Used in) Operating Activities | 579,464 | 625,206 | 546,954 |
Capital expenditures for development of crude oil and natural gas properties | (485,725) | (482,534) | (439,897) |
Capital expenditures for other properties and equipment | (20,361) | (9,806) | (3,539) |
Acquisition of crude oil and natural gas properties | (12,141) | (179,955) | (21,000) |
Proceeds from sale of properties and equipment | (399) | (1,929) | (10,084) |
Proceeds from divestitures | 5,515 | 44,693 | |
Proceeds from Sale of Notes Receivable | 40,203 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | (9,250) | ||
Restricted cash | 8,001 | ||
Sale of short-term investments | 49,890 | ||
Purchase of short-term investments | 49,890 | ||
intercompany Transfer Investing Activities | 105,004 | (199,584) | (239,191) |
Net Cash Provided by (Used in) Investing Activities | (399,308) | (824,008) | (662,590) |
Proceeds from issuance of senior notes | 592,366 | ||
Redemption of convertible notes | (519,375) | ||
Proceeds from Lines of Credit | 1,577,000 | 1,072,500 | |
Repayment of revolving credit facility | (1,605,500) | (1,040,000) | |
Payment of debt issuance costs | 72 | 7,704 | 50 |
Treasury Stock, Value, Acquired, Cost Method | 154,363 | 5,147 | 6,672 |
Purchase of treasury shares | 4,003 | ||
Finance Lease, Principal Payments | 1,654 | 1,318 | 1,092 |
Other | (55) | (103) | |
Intercompany Transfers Financing Activities | 0 | 0 | 0 |
Net Cash Provided by (Used in) Financing Activities | (188,592) | 18,276 | 65,074 |
Net change in cash, cash equivalents and restricted cash | (8,436) | (180,526) | (50,562) |
Cash, cash equivalents and restricted cash, beginning of year | 9,399 | 189,925 | 240,487 |
Cash, cash equivalents and restricted cash, end of year | 963 | 9,399 | 189,925 |
Reportable Legal Entities [Member] | |||
Net Cash Provided by (Used in) Operating Activities | 264,096 | 50,859 | |
Capital expenditures for development of crude oil and natural gas properties | (463,816) | (297,311) | |
Capital expenditures for other properties and equipment | (1,249) | (1,555) | |
Acquisition of crude oil and natural gas properties | 71 | (5,372) | |
Proceeds from sale of properties and equipment | (1,633) | (93) | |
Proceeds from Sale of Notes Receivable | 0 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | 0 | ||
Sale of short-term investments | 0 | ||
Purchase of short-term investments | 0 | ||
intercompany Transfer Investing Activities | 0 | 0 | |
Net Cash Provided by (Used in) Investing Activities | (463,503) | (293,587) | |
Consolidation, Eliminations [Member] | |||
Net Cash Provided by (Used in) Operating Activities | 0 | 0 | 0 |
Capital expenditures for development of crude oil and natural gas properties | 0 | 0 | 0 |
Capital expenditures for other properties and equipment | 0 | 0 | 0 |
Acquisition of crude oil and natural gas properties | 0 | 0 | 0 |
Proceeds from sale of properties and equipment | 0 | 0 | 0 |
Proceeds from divestitures | 0 | 0 | |
Proceeds from Sale of Notes Receivable | 0 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | 0 | ||
Restricted cash | 0 | 0 | |
Sale of short-term investments | 0 | ||
Purchase of short-term investments | 0 | ||
intercompany Transfer Investing Activities | (105,004) | 199,584 | 239,191 |
Net Cash Provided by (Used in) Investing Activities | (105,004) | 199,584 | 239,191 |
Proceeds from issuance of senior notes | 0 | ||
Redemption of convertible notes | 0 | ||
Proceeds from Lines of Credit | 0 | 0 | |
Repayment of revolving credit facility | 0 | 0 | |
Payment of debt issuance costs | 0 | 0 | 0 |
Treasury Stock, Value, Acquired, Cost Method | 0 | 0 | 0 |
Purchase of treasury shares | 0 | ||
Finance Lease, Principal Payments | 0 | 0 | 0 |
Other | 0 | 0 | |
Intercompany Transfers Financing Activities | 105,004 | (199,584) | (239,191) |
Net Cash Provided by (Used in) Financing Activities | 105,004 | (199,584) | (239,191) |
Net change in cash, cash equivalents and restricted cash | 0 | 0 | 0 |
Cash, cash equivalents and restricted cash, beginning of year | 0 | 0 | 0 |
Cash, cash equivalents and restricted cash, end of year | 0 | 0 | 0 |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Restricted cash | 1,249 | ||
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Net Cash Provided by (Used in) Operating Activities | 278,762 | ||
Capital expenditures for development of crude oil and natural gas properties | (370,183) | ||
Capital expenditures for other properties and equipment | (478) | ||
Acquisition of crude oil and natural gas properties | (1,066) | ||
Proceeds from sale of properties and equipment | (1,706) | ||
Proceeds from divestitures | 196,561 | 0 | |
Restricted cash | 0 | 0 | |
intercompany Transfer Investing Activities | 0 | ||
Net Cash Provided by (Used in) Investing Activities | (173,460) | ||
Proceeds from issuance of senior notes | 0 | ||
Redemption of convertible notes | 0 | ||
Proceeds from Lines of Credit | 0 | 0 | |
Repayment of revolving credit facility | 0 | 0 | |
Payment of debt issuance costs | 0 | 0 | 0 |
Treasury Stock, Value, Acquired, Cost Method | 0 | 0 | 0 |
Purchase of treasury shares | 0 | ||
Finance Lease, Principal Payments | 298 | 177 | 76 |
Other | 0 | 0 | |
Intercompany Transfers Financing Activities | (105,004) | 199,584 | 239,191 |
Net Cash Provided by (Used in) Financing Activities | (105,302) | 199,407 | 239,115 |
Net change in cash, cash equivalents and restricted cash | 0 | 0 | (3,613) |
Cash, cash equivalents and restricted cash, beginning of year | 0 | 0 | 3,613 |
Cash, cash equivalents and restricted cash, end of year | $ 0 | $ 0 | $ 0 |
SUPPLEMENTAL INFORMATION - NA_3
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Index price of reserves (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Crude Oil [Member] | ||||
oil and gas index price for reserves [Line Items] | ||||
oil and gas index price for reserves | [1] | $ 55.69 | $ 65.56 | $ 51.34 |
Natural Gas [Member] | ||||
oil and gas index price for reserves [Line Items] | ||||
oil and gas index price for reserves | [1] | 2.58 | 3.10 | 2.98 |
Natural Gas Liquids (Bbls) | ||||
oil and gas index price for reserves [Line Items] | ||||
oil and gas index price for reserves | [1] | $ 55.69 | $ 65.56 | $ 51.34 |
[1] | Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. |
SUPPLEMENTAL INFORMATION - NA_4
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Crude Oil [Member] | ||||
Schedule of Prices Used to Estimate Reserves [Line Items] | ||||
prices used to estimate oil and gas reserves | [1] | $ 52.63 | $ 61.14 | $ 48.68 |
Natural Gas [Member] | ||||
Schedule of Prices Used to Estimate Reserves [Line Items] | ||||
prices used to estimate oil and gas reserves | [1] | 1.50 | 2.15 | 2.31 |
Natural Gas Liquids (Bbls) | ||||
Schedule of Prices Used to Estimate Reserves [Line Items] | ||||
prices used to estimate oil and gas reserves | [1],[2] | $ 12.21 | $ 23.04 | $ 20.21 |
[1] | These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. | |||
[2] | For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. |
SUPPLEMENTAL INFORMATION - NA_5
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) MMcf in Thousands, MBbls in Thousands, MMBoe in Millions, MMBbls in Millions | 12 Months Ended | |||||||||||||||||
Dec. 31, 2019MBblsMMcf | Dec. 31, 2019RateMBblsMMcf | Dec. 31, 2019MBblsMMcf | Dec. 31, 2019MBblsMMcf | Dec. 31, 2019MBblsMMcf | Dec. 31, 2019MMBoeMBblsMMcf | Dec. 31, 2019MBblsMMcfMMBbls | Dec. 31, 2018RateMBblsMMcf | Dec. 31, 2018MBblsMMcf | Dec. 31, 2018MBblsMMcf | Dec. 31, 2018MBblsMMcf | Dec. 31, 2018MBblsMMcfMMBbls | Dec. 31, 2017RateMBblsMMcf | Dec. 31, 2017MBblsMMcf | Dec. 31, 2017MBblsMMcf | Dec. 31, 2017MMBoeMBblsMMcf | Dec. 31, 2017MBblsMMcfMMBbls | Dec. 31, 2016MBblsMMcf | |
Reserve Quantities [Line Items] | ||||||||||||||||||
Document Period End Date | Dec. 31, 2019 | |||||||||||||||||
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe | 65.9 | |||||||||||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 12.00% | |||||||||||||||||
Proved Reserves | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 544,953 | 544,953 | 544,953 | 544,953 | 544,953 | 452,917 | 452,917 | 452,917 | 452,917 | 452,917 | 341,407 |
Production | 49,414 | 40,160 | 31,830 | |||||||||||||||
Undeveloped Reserves Converted to Developed | 0 | 0 | 0 | |||||||||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | |||||||||||||||
Dispositions | (2,868) | (11,121) | (1,900) | |||||||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | |||||||||||||||
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | |||||||||||||||
Increase or Decrease in Proved Reserves | MMBbls | 92 | |||||||||||||||||
Proved Undeveloped Reserves [Member] | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe | 111.5 | |||||||||||||||||
Proved Reserves | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 365,418 | 365,418 | 365,418 | 365,418 | 365,418 | 309,946 | 309,946 | 309,946 | 309,946 | 309,946 | 243,122 |
Production | 0 | 0 | 0 | |||||||||||||||
Undeveloped Reserves Converted to Developed | (52,169) | (58,294) | (54,648) | |||||||||||||||
Purchases of Reserves | 1,320 | 51,602 | 85,473 | |||||||||||||||
Acquisition Of Reserves Acreage Swaps | MMBbls | 1.3 | 47.6 | 85.5 | |||||||||||||||
Acquisition Of Reserves Acquisition | MMBbls | 4 | |||||||||||||||||
Dispositions | 2,394 | 2.4 | 6,635 | 6.6 | 1,880 | 1.9 | ||||||||||||
Extensions, Discoveries, and Other Additions | 0 | 20,072 | 20.1 | 3,713 | 3.7 | |||||||||||||
Newly Drilled Wells Gross | 16 | |||||||||||||||||
Newly Drilled Wells Net | 15 | |||||||||||||||||
Revisions of Previous Estimates | 84,695 | 74.2 | 48,727 | 71.7 | 34,166 | 89.8 | ||||||||||||
Upward Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area | MMBbls | 12.9 | 26.8 | 58.5 | |||||||||||||||
Majority of upward downward revision of our previous estimate of proved reserves | MMBbls | 23.4 | 3.8 | 2.9 | |||||||||||||||
Actual PUD conversion rate | Rate | 14.00% | 19.00% | 23.00% | |||||||||||||||
Proved Developed Reserves [Member] | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Reserves | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 179,535 | 179,535 | 179,535 | 179,535 | 179,535 | 142,971 | 142,971 | 142,971 | 142,971 | 142,971 | 98,285 |
Production | (49,414) | (49.4) | (40,160) | (40.2) | (31,830) | (31.8) | ||||||||||||
Upward (Downward) Revision due to change in SEC pricing | MMBbls | 17.3 | 11.4 | 17.7 | |||||||||||||||
Additional Change in Reserves | MMBbls | 10.2 | 5.1 | 0.6 | |||||||||||||||
Undeveloped Reserves Converted to Developed | 52,169 | 52.2 | 58,294 | 58.3 | 54,648 | 54.6 | ||||||||||||
Purchases of Reserves | 441 | 0.4 | 8,758 | 8.8 | 1,305 | 1.3 | ||||||||||||
Dispositions | 474 | 0.5 | 4,486 | 4.5 | 20 | |||||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 4.3 | 7,874 | 7.9 | 2,292 | 2.3 | ||||||||||||
Newly Drilled Wells Gross | 3 | 17 | ||||||||||||||||
Newly Drilled Wells Net | 3 | 9.2 | ||||||||||||||||
Revisions of Previous Estimates | 27,452 | 6,284 | 18,291 | |||||||||||||||
Crude Oil [Member] | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Reserves | 197,255 | 197,255 | 197,255 | 197,255 | 197,255 | 197,255 | 197,255 | 190,349 | 190,349 | 190,349 | 190,349 | 190,349 | 154,842 | 154,842 | 154,842 | 154,842 | 154,842 | 118,169 |
Production | (19,166) | (16,964) | (12,902) | |||||||||||||||
Purchases of Reserves | 553 | 19,644 | 18,971 | |||||||||||||||
Dispositions | 1,412 | 2,507 | 653 | |||||||||||||||
Extensions, Discoveries, and Other Additions | 1,056 | 8,786 | 2,923 | |||||||||||||||
Revisions of Previous Estimates | 25,875 | 26,548 | 28,334 | |||||||||||||||
Proved Developed Reserves | 66,211 | 66,211 | 66,211 | 66,211 | 66,211 | 66,211 | 66,211 | 61,821 | 61,821 | 61,821 | 61,821 | 61,821 | 46,862 | 46,862 | 46,862 | 46,862 | 46,862 | |
Proved Undeveloped Reserve | 131,044 | 131,044 | 131,044 | 131,044 | 131,044 | 131,044 | 131,044 | 128,528 | 128,528 | 128,528 | 128,528 | 128,528 | 107,980 | 107,980 | 107,980 | 107,980 | 107,980 | |
Natural Gas [Member] | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Reserves | MMcf | 1,557,797 | 1,557,797 | 1,557,797 | 1,557,797 | 1,557,797 | 1,557,797 | 1,557,797 | 1,335,689 | 1,335,689 | 1,335,689 | 1,335,689 | 1,335,689 | 1,154,294 | 1,154,294 | 1,154,294 | 1,154,294 | 1,154,294 | 833,697 |
Production | MMcf | (115,950) | (88,017) | (71,689) | |||||||||||||||
Purchases of Reserves | MMcf | 4,558 | 148,674 | 289,223 | |||||||||||||||
Dispositions | MMcf | 5,052 | 35,750 | 4,597 | |||||||||||||||
Extensions, Discoveries, and Other Additions | MMcf | 10,262 | 61,750 | 11,541 | |||||||||||||||
Revisions of Previous Estimates | MMcf | 328,290 | 94,738 | 96,119 | |||||||||||||||
Proved Developed Reserves | MMcf | 554,234 | 554,234 | 554,234 | 554,234 | 554,234 | 554,234 | 554,234 | 443,151 | 443,151 | 443,151 | 443,151 | 443,151 | 365,332 | 365,332 | 365,332 | 365,332 | 365,332 | |
Proved Undeveloped Reserve | MMcf | 1,003,563 | 1,003,563 | 1,003,563 | 1,003,563 | 1,003,563 | 1,003,563 | 1,003,563 | 892,538 | 892,538 | 892,538 | 892,538 | 892,538 | 788,962 | 788,962 | 788,962 | 788,962 | 788,962 | |
Natural Gas Liquids (Bbls) | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Reserves | 153,976 | 153,976 | 153,976 | 153,976 | 153,976 | 153,976 | 153,976 | 131,987 | 131,987 | 131,987 | 131,987 | 131,987 | 105,692 | 105,692 | 105,692 | 105,692 | 105,692 | 84,288 |
Production | (10,923) | (8,527) | (6,981) | |||||||||||||||
Purchases of Reserves | 448 | 15,936 | 19,604 | |||||||||||||||
Dispositions | 614 | 2,656 | 481 | |||||||||||||||
Extensions, Discoveries, and Other Additions | 1,519 | 8,868 | 1,158 | |||||||||||||||
Revisions of Previous Estimates | 31,559 | 12,674 | 8,104 | |||||||||||||||
Proved Developed Reserves | 55,411 | 55,411 | 55,411 | 55,411 | 55,411 | 55,411 | 55,411 | 43,856 | 43,856 | 43,856 | 43,856 | 43,856 | 35,220 | 35,220 | 35,220 | 35,220 | 35,220 | |
Proved Undeveloped Reserve | 98,565 | 98,565 | 98,565 | 98,565 | 98,565 | 98,565 | 98,565 | 88,131 | 88,131 | 88,131 | 88,131 | 88,131 | 70,472 | 70,472 | 70,472 | 70,472 | 70,472 | |
Crude Oil Equivalent (Boe) | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved Reserves | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 610,864 | 544,953 | 544,953 | 544,953 | 544,953 | 544,953 | 452,917 | 452,917 | 452,917 | 452,917 | 452,917 | 341,407 |
Production | (49,414) | (40,160) | (31,830) | |||||||||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | |||||||||||||||
Dispositions | 2,868 | 11,121 | 1,900 | |||||||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | |||||||||||||||
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | |||||||||||||||
Proved Developed Reserves | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 213,994 | 179,535 | 179,535 | 179,535 | 179,535 | 179,535 | 142,971 | 142,971 | 142,971 | 142,971 | 142,971 | |
Proved Undeveloped Reserve | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 396,870 | 365,418 | 365,418 | 365,418 | 365,418 | 365,418 | 309,946 | 309,946 | 309,946 | 309,946 | 309,946 | |
Year-over-Year Activity [Domain] | ||||||||||||||||||
Reserve Quantities [Line Items] | ||||||||||||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 20.00% | 33.00% | ||||||||||||||||
Estimated PUD conversion rate for following year | Rate | 26.00% | 16.00% | 26.00% |
SUPPLEMENTAL INFORMATION - NA_6
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details) MBbls in Thousands, MMBbls in Millions | 12 Months Ended | ||||||||||
Dec. 31, 2019MBbls | Dec. 31, 2019RateMBbls | Dec. 31, 2019MBbls | Dec. 31, 2019MBblsMMBbls | Dec. 31, 2018RateMBbls | Dec. 31, 2018MBbls | Dec. 31, 2018MBblsMMBbls | Dec. 31, 2017RateMBbls | Dec. 31, 2017MBbls | Dec. 31, 2017MBblsMMBbls | Dec. 31, 2016MBbls | |
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Document Period End Date | Dec. 31, 2019 | ||||||||||
Proved Developed and Undeveloped Reserves, Net | 610,864 | 610,864 | 610,864 | 610,864 | 544,953 | 544,953 | 544,953 | 452,917 | 452,917 | 452,917 | 341,407 |
Undeveloped Reserves Converted to Developed | 0 | 0 | 0 | ||||||||
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | ||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | ||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | ||||||||
Dispositions | 2,868 | 11,121 | 1,900 | ||||||||
Production | 49,414 | 40,160 | 31,830 | ||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 12.00% | ||||||||||
Increase or Decrease in Proved Reserves | MMBbls | 92 | ||||||||||
Proved Undeveloped Reserves [Member] | |||||||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Majority of upward downward revision of our previous estimate of proved reserves | MMBbls | 23.4 | 3.8 | 2.9 | ||||||||
Proved Developed and Undeveloped Reserves, Net | 396,870 | 396,870 | 396,870 | 396,870 | 365,418 | 365,418 | 365,418 | 309,946 | 309,946 | 309,946 | 243,122 |
Undeveloped Reserves Converted to Developed | (52,169) | (58,294) | (54,648) | ||||||||
Revisions of Previous Estimates | 84,695 | 74.2 | 48,727 | 71.7 | 34,166 | 89.8 | |||||
Extensions, Discoveries, and Other Additions | 0 | 20,072 | 20.1 | 3,713 | 3.7 | ||||||
Purchases of Reserves | 1,320 | 51,602 | 85,473 | ||||||||
Acquisition Of Reserves Acreage Swaps | MMBbls | 1.3 | 47.6 | 85.5 | ||||||||
Dispositions | (2,394) | (2.4) | (6,635) | (6.6) | (1,880) | (1.9) | |||||
Production | 0 | 0 | 0 | ||||||||
Actual PUD conversion rate | Rate | 14.00% | 19.00% | 23.00% | ||||||||
Upward Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area | MMBbls | 12.9 | 26.8 | 58.5 | ||||||||
Proved Developed Reserves [Member] | |||||||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Proved Developed and Undeveloped Reserves, Net | 213,994 | 213,994 | 213,994 | 213,994 | 179,535 | 179,535 | 179,535 | 142,971 | 142,971 | 142,971 | 98,285 |
Undeveloped Reserves Converted to Developed | 52,169 | 52.2 | 58,294 | 58.3 | 54,648 | 54.6 | |||||
Revisions of Previous Estimates | 27,452 | 6,284 | 18,291 | ||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 4.3 | 7,874 | 7.9 | 2,292 | 2.3 | |||||
Purchases of Reserves | 441 | 0.4 | 8,758 | 8.8 | 1,305 | 1.3 | |||||
Dispositions | (474) | (0.5) | (4,486) | (4.5) | (20) | ||||||
Production | (49,414) | (49.4) | (40,160) | (40.2) | (31,830) | (31.8) | |||||
Upward (Downward) Revision due to change in SEC pricing | MMBbls | 17.3 | 11.4 | 17.7 | ||||||||
Additional Change in Reserves | MMBbls | 10.2 | 5.1 | 0.6 | ||||||||
Crude Oil Equivalent (Boe) | |||||||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Proved Developed and Undeveloped Reserves, Net | 610,864 | 610,864 | 610,864 | 610,864 | 544,953 | 544,953 | 544,953 | 452,917 | 452,917 | 452,917 | 341,407 |
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | ||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | ||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | ||||||||
Dispositions | (2,868) | (11,121) | (1,900) | ||||||||
Production | (49,414) | (40,160) | (31,830) | ||||||||
Crude Oil [Member] | |||||||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Proved Developed and Undeveloped Reserves, Net | 197,255 | 197,255 | 197,255 | 197,255 | 190,349 | 190,349 | 190,349 | 154,842 | 154,842 | 154,842 | 118,169 |
Revisions of Previous Estimates | 25,875 | 26,548 | 28,334 | ||||||||
Extensions, Discoveries, and Other Additions | 1,056 | 8,786 | 2,923 | ||||||||
Purchases of Reserves | 553 | 19,644 | 18,971 | ||||||||
Dispositions | (1,412) | (2,507) | (653) | ||||||||
Production | (19,166) | (16,964) | (12,902) | ||||||||
Year-over-Year Activity [Domain] | |||||||||||
Schedule of Developed and Undeveloped Reserves [Line Items] | |||||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 20.00% | 33.00% |
SUPPLEMENTAL INFORMATION - NA_7
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) MBbls in Thousands, $ in Thousands, MMBbls in Millions | 12 Months Ended | ||||||||
Dec. 31, 2019MBbls | Dec. 31, 2019USD ($) | Dec. 31, 2019MMBbls | Dec. 31, 2018MBbls | Dec. 31, 2018USD ($) | Dec. 31, 2018MMBbls | Dec. 31, 2017MBbls | Dec. 31, 2017USD ($) | Dec. 31, 2017MMBbls | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||||||||
Undeveloped Reserves Converted to Developed | MBbls | 0 | 0 | 0 | ||||||
Extensions, Discoveries, and Other Additions | MBbls | 4,285 | 27,946 | 6,005 | ||||||
Purchases of Reserves | MBbls | 1,761 | 60,360 | 86,778 | ||||||
Revisions of Previous Estimates | MBbls | 112,147 | 55,011 | 52,457 | ||||||
Production | MBbls | (49,414) | (40,160) | (31,830) | ||||||
Dispositions | MBbls | (2,868) | (11,121) | (1,900) | ||||||
Total Revenues from Oil and Gas Producing Activities | $ 1,307,275 | $ 1,389,961 | $ 913,084 | ||||||
Lease operating expenses | 142,248 | 130,957 | 89,641 | ||||||
Production taxes | 80,754 | 90,357 | 60,717 | ||||||
Transportation, gathering and processing expenses | 46,353 | 37,403 | 33,220 | ||||||
Results of Operations for Crude Oil and Natural Gas Producing Activities | |||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||||||||
Natural gas, NGL and crude oil sales | 1,307,275 | 1,389,961 | 913,084 | ||||||
Commodity price risk management | (162,844) | 145,237 | (3,936) | ||||||
Total Revenues from Oil and Gas Producing Activities | 1,144,431 | 1,535,198 | 909,148 | ||||||
Lease operating expenses | 142,248 | 130,957 | 89,641 | ||||||
Production taxes | 80,754 | 90,357 | 60,717 | ||||||
Transportation, gathering and processing expenses | 46,353 | 37,403 | 33,220 | ||||||
Exploration Expense | 4,054 | 6,204 | 47,334 | ||||||
Impairment of Oil and Gas Properties | 38,536 | 458,397 | 285,887 | ||||||
Depreciation, Depletion and Amortization | 638,499 | 551,265 | 462,482 | ||||||
Accretion of Asset Retirement Obligations | 6,117 | 5,075 | 6,306 | ||||||
(Gain) loss on Sale of Properties and Equipment | 9,734 | 394 | (766) | ||||||
Total Expense from Oil and Gas Producing Activities | 966,295 | 1,280,052 | 984,821 | ||||||
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes | 178,136 | 255,146 | (75,673) | ||||||
Provision for Income Taxes | (9,869) | (185,667) | 47,247 | ||||||
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs | $ 168,267 | $ 69,479 | $ (28,426) | ||||||
Proved Developed Reserves [Member] | |||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||||||||
Undeveloped Reserves Converted to Developed | 52,169 | 52.2 | 58,294 | 58.3 | 54,648 | 54.6 | |||
Extensions, Discoveries, and Other Additions | 4,285 | 4.3 | 7,874 | 7.9 | 2,292 | 2.3 | |||
Purchases of Reserves | 441 | 0.4 | 8,758 | 8.8 | 1,305 | 1.3 | |||
Revisions of Previous Estimates | MBbls | 27,452 | 6,284 | 18,291 | ||||||
Production | 49,414 | 49.4 | 40,160 | 40.2 | 31,830 | 31.8 | |||
Dispositions | 474 | 0.5 | 4,486 | 4.5 | 20 | ||||
Proved Undeveloped Reserves [Member] | |||||||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||||||||
Undeveloped Reserves Converted to Developed | MBbls | (52,169) | (58,294) | (54,648) | ||||||
Extensions, Discoveries, and Other Additions | 0 | 20,072 | 20.1 | 3,713 | 3.7 | ||||
Purchases of Reserves | MBbls | 1,320 | 51,602 | 85,473 | ||||||
Acquisition Of Reserves Acreage Swaps | MMBbls | 1.3 | 47.6 | 85.5 | ||||||
Revisions of Previous Estimates | 84,695 | 74.2 | 48,727 | 71.7 | 34,166 | 89.8 | |||
Production | MBbls | 0 | 0 | 0 | ||||||
Dispositions | 2,394 | 2.4 | 6,635 | 6.6 | 1,880 | 1.9 |
SUPPLEMENTAL INFORMATION - NA_8
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) MBbls in Thousands, $ in Thousands, MMBoe in Millions, MMBbls in Millions | 12 Months Ended | |||||||||||||||
Dec. 31, 2019 | Dec. 31, 2019Rate | Dec. 31, 2019MBbls | Dec. 31, 2019USD ($) | Dec. 31, 2019MMBoe | Dec. 31, 2019MMBbls | Dec. 31, 2018Rate | Dec. 31, 2018MBbls | Dec. 31, 2018USD ($) | Dec. 31, 2018MMBbls | Dec. 31, 2017Rate | Dec. 31, 2017MBbls | Dec. 31, 2017USD ($) | Dec. 31, 2017MMBoe | Dec. 31, 2017MMBbls | ||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||||||||||||
Document Period End Date | Dec. 31, 2019 | |||||||||||||||
Dispositions | (2,868) | (11,121) | (1,900) | |||||||||||||
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe | 65.9 | |||||||||||||||
Proved Properties | $ | [1] | $ 16,007 | $ 205,253 | $ 172 | ||||||||||||
Unproved Properties | $ | [1] | 9,567 | 5,477 | 18,914 | ||||||||||||
Development Costs | $ | [2] | 780,851 | 970,970 | 688,165 | ||||||||||||
Exploratory drilling | $ | [3] | 32,218 | 36,704 | 80,103 | ||||||||||||
Geological and geophysical | $ | [3] | 3,017 | 3,401 | 3,881 | ||||||||||||
Total Costs Incurred | $ | 841,660 | 1,221,805 | 791,235 | |||||||||||||
Cost Incurred to Convert PUDs to PDNP | $ | 308,900 | 438,400 | 463,400 | |||||||||||||
Cost Incurred to Convert PUDs to PDNP, Infrastructure And Pipeline Costs | $ | $ 35,300 | $ 74,600 | 32,800 | |||||||||||||
Reduction To Proved, Undeveloped And Development Costs | $ | $ 24,600 | |||||||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | |||||||||||||
Undeveloped Reserves Converted to Developed | 0 | 0 | 0 | |||||||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 12.00% | |||||||||||||||
Increase or Decrease in Proved Reserves | MMBbls | 92 | |||||||||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | |||||||||||||
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | |||||||||||||
Production | (49,414) | (40,160) | (31,830) | |||||||||||||
Year-over-Year Activity [Domain] | ||||||||||||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||||||||||||
Estimated PUD conversion rate for following year | Rate | 26.00% | 16.00% | 26.00% | |||||||||||||
Proved developed and undeveloped reserves percent increase or decrease | Rate | 20.00% | 33.00% | ||||||||||||||
Proved Developed Reserves [Member] | ||||||||||||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||||||||||||
Dispositions | 474 | 0.5 | 4,486 | 4.5 | 20 | |||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 4.3 | 7,874 | 7.9 | 2,292 | 2.3 | ||||||||||
Undeveloped Reserves Converted to Developed | 52,169 | 52.2 | 58,294 | 58.3 | 54,648 | 54.6 | ||||||||||
Purchases of Reserves | 441 | 0.4 | 8,758 | 8.8 | 1,305 | 1.3 | ||||||||||
Revisions of Previous Estimates | 27,452 | 6,284 | 18,291 | |||||||||||||
Production | 49,414 | 49.4 | 40,160 | 40.2 | 31,830 | 31.8 | ||||||||||
Proved Undeveloped Reserves [Member] | ||||||||||||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||||||||||||
Dispositions | 2,394 | 2.4 | 6,635 | 6.6 | 1,880 | 1.9 | ||||||||||
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MMBoe | 111.5 | |||||||||||||||
Extensions, Discoveries, and Other Additions | 0 | 20,072 | 20.1 | 3,713 | 3.7 | |||||||||||
Actual PUD conversion rate | Rate | 14.00% | 19.00% | 23.00% | |||||||||||||
Undeveloped Reserves Converted to Developed | (52,169) | (58,294) | (54,648) | |||||||||||||
Purchases of Reserves | 1,320 | 51,602 | 85,473 | |||||||||||||
Revisions of Previous Estimates | 84,695 | 74.2 | 48,727 | 71.7 | 34,166 | 89.8 | ||||||||||
Production | 0 | 0 | 0 | |||||||||||||
Crude Oil Equivalent (Boe) | ||||||||||||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||||||||||||
Dispositions | 2,868 | 11,121 | 1,900 | |||||||||||||
Extensions, Discoveries, and Other Additions | 4,285 | 27,946 | 6,005 | |||||||||||||
Purchases of Reserves | 1,761 | 60,360 | 86,778 | |||||||||||||
Revisions of Previous Estimates | 112,147 | 55,011 | 52,457 | |||||||||||||
Production | 49,414 | 40,160 | 31,830 | |||||||||||||
[1] | Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. | |||||||||||||||
[2] | Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019 , 2018 and 2017 , $308.9 million , $438.4 million and $463.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $35.3 million , $74.6 million and $32.8 million of infrastructure and pipeline costs in 2019 , 2018 and 2017 respectively. (3) | |||||||||||||||
[3] | Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. |
SUPPLEMENTAL INFORMATION - NA_9
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||
Proved natural gas and crude oil properties | $ 6,241,780 | $ 5,452,613 |
Unproved natural gas and crude oil properties | 403,379 | 492,594 |
Uncompleted Wells, Equipment and Facilities | 382,409 | 332,264 |
Capitalized Costs | 7,027,568 | 6,277,471 |
Less accumulated DD&A | (2,982,929) | (2,341,897) |
Capitalized Costs, Net | $ 4,044,639 | $ 3,935,574 |
SUPPLEMENTAL INFORMATION - N_10
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) MBbls in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019USD ($)MBbls | Dec. 31, 2018USD ($)MBbls | Dec. 31, 2017USD ($)MBbls | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Dispositions | MBbls | (2,868) | (11,121) | (1,900) |
Future Estimated Cash Flows | $ 14,590,604 | $ 17,554,880 | $ 12,340,407 |
Future Estimated Production Costs | (4,530,173) | (4,782,948) | (3,245,627) |
Future Estimated Development Costs | (3,257,106) | (3,632,822) | (2,893,335) |
Future Estimated Income Tax Expense | (907,382) | (1,404,121) | (748,494) |
Future Net Cash Flows | 5,895,943 | 7,734,989 | 5,452,951 |
10% Annual Discount for Estimated Timing of Cash Flows | (2,585,609) | (3,287,273) | (2,572,846) |
Standardized Measure of Disconted Future Estimated Net Cash Flows | $ 3,310,334 | $ 4,447,716 | $ 2,880,105 |
Crude Oil [Member] | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Dispositions | MBbls | 1,412 | 2,507 | 653 |
SUPPLEMENTAL INFORMATION - N_11
SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Unuadited) (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Principal Sources of Change: | |||||
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Period Increase (Decrease) | $ 3,310,334,000 | $ 4,447,716,000 | $ 2,880,105,000 | $ 1,420,629,000 | |
Sales of natural gas, NGL and crude oil production, net of production costs | (1,037,920,000) | (1,131,244,000) | (729,506,000) | ||
Net changes in prices and production costs | [1] | (2,122,538,000) | 936,077,000 | 841,713,000 | |
Extensions, discoveries and improved recovery, less related costs | 39,606,000 | 190,084,000 | 47,240,000 | ||
Sales of reserves | (14,533,000) | (42,362,000) | (2,613,000) | ||
Purchases of reserves | 18,816,000 | 467,807,000 | 224,483,000 | ||
Development costs incurred during the period | 605,753,000 | 462,088,000 | 419,047,000 | ||
Revisions of previous quantity estimates | 538,242,000 | 631,198,000 | 484,431,000 | ||
Changes in estimated income taxes | 346,826,000 | (232,002,000) | (138,560,000) | ||
Net change in future development costs | 206,003,000 | (123,663,000) | 25,183,000 | ||
Accretion of discount | 532,127,000 | 583,744,000 | 167,487,000 | ||
Timing and other | (249,764,000) | (174,116,000) | 120,571,000 | ||
Notes to Changes in SMOG [Abstract] | |||||
Weighted-Average price, net of production cost | $ 16.18 | $ 23.44 | $ 20.08 | ||
[1] | Our weighted-average price, net of production costs per Boe, in our 2019 reserve report decreased to $16.18 as compared to $23.44 for 2018 and $20.08 for 2017 . |
SUPPLEMENTAL INFORMATION - QU_3
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues: | |||||||||||
Revenues | $ 265,022 | $ 365,943 | $ 390,658 | $ 134,500 | $ 794,811 | $ 280,717 | $ 212,531 | $ 260,600 | $ 1,156,123 | $ 1,548,659 | $ 921,616 |
Costs, expenses and other: | |||||||||||
Total cost, expenses and other | 267,713 | 321,562 | 280,623 | 275,120 | 538,626 | 270,593 | 400,770 | 260,924 | 1,145,018 | 1,470,913 | 1,159,868 |
Operating Income (Loss) | (2,691) | 44,381 | 110,035 | (140,620) | 256,185 | 10,124 | (188,239) | (324) | 11,105 | 77,746 | (238,252) |
Income (loss) before income taxes | (20,111) | 26,570 | 91,135 | (157,588) | 238,024 | (7,310) | (205,580) | (17,705) | (59,994) | 7,429 | (339,432) |
Net income (loss) | $ (20,952) | $ 15,908 | $ 68,548 | $ (120,176) | $ 178,853 | $ (3,434) | $ (160,257) | $ (13,139) | $ (56,672) | $ 2,023 | $ (127,504) |
Basic | |||||||||||
Basic | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
Diluted | |||||||||||
Diluted | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
Deferred income taxes | $ (2,256) | $ 6,105 | $ (203,685) |
SUPPLEMENTAL INFORMATION - QU_4
SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION Quarterly Income Statement Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues | $ 265,022 | $ 365,943 | $ 390,658 | $ 134,500 | $ 794,811 | $ 280,717 | $ 212,531 | $ 260,600 | $ 1,156,123 | $ 1,548,659 | $ 921,616 |
Total cost, expenses and other | 267,713 | 321,562 | 280,623 | 275,120 | 538,626 | 270,593 | 400,770 | 260,924 | 1,145,018 | 1,470,913 | 1,159,868 |
Operating Income (Loss) | (2,691) | 44,381 | 110,035 | (140,620) | 256,185 | 10,124 | (188,239) | (324) | 11,105 | 77,746 | (238,252) |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest | (20,111) | 26,570 | 91,135 | (157,588) | 238,024 | (7,310) | (205,580) | (17,705) | (59,994) | 7,429 | (339,432) |
Net income (loss) | $ (20,952) | $ 15,908 | $ 68,548 | $ (120,176) | $ 178,853 | $ (3,434) | $ (160,257) | $ (13,139) | $ (56,672) | $ 2,023 | $ (127,504) |
Basic | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
Diluted | $ (0.34) | $ 0.25 | $ 1.04 | $ (1.82) | $ 2.71 | $ (0.05) | $ (2.43) | $ (0.20) | $ (0.89) | $ 0.03 | $ (1.94) |
SCHEDULE II - VALUATION AND Q_3
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
SEC Schedule, 12-09, Reserve, Impairment of Recognized Servicing Asset [Member] | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | $ 8,523 | $ 388,068 | $ 263,817 | ||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | 544,351 | [1] | 96,518 | 13,017 | [1] | ||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | 6,881 | 542,709 | 251,159 | $ 359 | |||
allowance for uncollectible notes [Member] | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
Financing Receivable, Allowance for Credit Loss, Noncurrent | 0 | 44,038 | |||||
Increase (Decrease) in Notes Receivables | [1] | 0 | |||||
Increase (Decrease) in Accounts and Notes Receivable | 44,038 | ||||||
SEC Schedule, 12-09, Allowance, Credit Loss [Member] | |||||||
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | 3,209 | 1,276 | 1,108 | ||||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | [1] | 114 | 23 | 170 | |||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount | $ 7,476 | $ 4,381 | $ 3,128 | $ 2,190 | |||
[1] | For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. |