Cover
Cover - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 21, 2020 | Jun. 28, 2019 | |
Cover page. | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2019 | ||
Document Transition Report | false | ||
Entity File Number | 001-33784 | ||
Entity Registrant Name | SANDRIDGE ENERGY, INC. | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 20-8084793 | ||
Entity Address, Address Line One | 123 Robert S. Kerr Avenue | ||
Entity Address, City or Town | Oklahoma City | ||
Entity Address, State or Province | OK | ||
Entity Address, Postal Zip Code | 73102 | ||
City Area Code | 405 | ||
Local Phone Number | 429-5500 | ||
Title of 12(b) Security | Common Stock, $0.001 par value | ||
Trading Symbol | SD | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Bankruptcy Proceedings, Reporting Current | true | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 211.1 | ||
Entity Common Stock, Shares Outstanding | 35,772,204 | ||
Documents Incorporated by Reference | Portions of the Company’s definitive proxy statement for the 2019 Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of December 31, 2019, are incorporated by reference in Part III. | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Central Index Key | 0001349436 | ||
Current Fiscal Year End Date | --12-31 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 4,275 | $ 17,660 |
Restricted cash - other | 1,693 | 1,985 |
Accounts receivable, net | 28,644 | 45,503 |
Derivative contracts | 114 | 5,286 |
Prepaid expenses | 3,342 | 2,628 |
Other current assets | 538 | 265 |
Total current assets | 38,606 | 73,327 |
Oil and natural gas properties, using full cost method of accounting | ||
Proved | 1,484,359 | 1,269,091 |
Unproved | 24,603 | 60,152 |
Less: accumulated depreciation, depletion and impairment | (1,129,622) | (580,132) |
Net oil and natural gas properties capitalized costs | 379,340 | 749,111 |
Other property, plant and equipment, net | 188,603 | |
Other property, plant and equipment, net | 200,838 | |
Other assets | 1,140 | 1,062 |
Total assets | 607,689 | 1,024,338 |
Current liabilities | ||
Accounts payable and accrued expenses | 64,937 | 111,797 |
Asset retirement obligations | 22,119 | 25,393 |
Other current liabilities | 1,367 | 0 |
Total current liabilities | 88,423 | 137,190 |
Long-term debt | 57,500 | 0 |
Asset retirement obligations | 52,897 | 34,671 |
Other long-term obligations | 6,417 | 4,756 |
Total liabilities | 205,237 | 176,617 |
Commitments and contingencies (Note 13) | ||
Stockholders’ Equity | ||
Common stock, $0.001 par value; 250,000 shares authorized; 35,772 issued and outstanding at December 31, 2019 and 35,687 issued and outstanding at December 31, 2018 | 36 | 36 |
Warrants | 88,520 | 88,516 |
Additional paid-in capital | 1,059,253 | 1,055,164 |
Accumulated deficit | (745,357) | (295,995) |
Total stockholders’ equity | 402,452 | 847,721 |
Total liabilities and stockholders’ equity | $ 607,689 | $ 1,024,338 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common Stock, Shares Authorized | 250,000,000 | 250,000,000 |
Common stock, issued (in shares) | 35,772,000 | 35,687,000 |
Common stock, outstanding (in shares) | 35,772,000 | 35,687,000 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues | |||
Total revenues | $ 266,845 | $ 349,395 | $ 357,299 |
Expenses | |||
Lease operating expenses | 90,938 | 87,786 | 99,052 |
Production, ad valorem, and other taxes | 19,394 | 25,434 | 18,211 |
Depreciation and depletion—oil and natural gas | 146,874 | 127,281 | 118,035 |
Depreciation and amortization—other | 11,684 | 11,982 | 13,852 |
Impairment | 409,574 | 4,170 | 4,019 |
General and administrative | 32,058 | 40,619 | 75,133 |
Accelerated vesting of employment compensation | 0 | 6,545 | 0 |
Proxy contest | 0 | 7,139 | 0 |
Terminated merger costs | 0 | 0 | 8,162 |
Employee termination benefits | 4,792 | 32,657 | 4,815 |
(Gain) loss on derivative contracts | (1,094) | 17,155 | (24,090) |
Other operating (income) expense | (608) | (998) | 479 |
Total expenses | 713,612 | 359,770 | 317,668 |
(Loss) income from operations | (446,767) | (10,375) | 39,631 |
Other (expense) income | |||
Interest expense, net | (2,974) | (2,787) | (3,868) |
Gain on extinguishment of debt | 0 | 1,151 | 0 |
Other income, net | 436 | 2,865 | 2,550 |
Total other (expense) income | (2,538) | 1,229 | (1,318) |
(Loss) income before income taxes | (449,305) | (9,146) | 38,313 |
Income tax benefit | 0 | (71) | (8,749) |
Net (loss) income | $ (449,305) | $ (9,075) | $ 47,062 |
(Loss) earnings per share | |||
Basic (in dollars per share) | $ (12.68) | $ (0.26) | $ 1.45 |
Diluted (in dollars per share) | $ (12.68) | $ (0.26) | $ 1.44 |
Weighted average number of common shares outstanding | |||
Basic (in shares) | 35,427 | 35,057 | 32,442 |
Diluted (in shares) | 35,427 | 35,057 | 32,663 |
Oil, natural gas and NGL | |||
Revenues | |||
Total revenues | $ 266,104 | $ 348,726 | $ 356,210 |
Other | |||
Revenues | |||
Total revenues | $ 741 | $ 669 | $ 1,089 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Stockholders Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Warrants | Additional Paid-In Capital | Accumulated Deficit |
Beginning Balance (in shares) at Dec. 31, 2016 | 19,635 | 6,442 | |||
Beginning Balance at Dec. 31, 2016 | $ 512,917 | $ 20 | $ 88,381 | $ 758,498 | $ (333,982) |
Increase (Decrease) in Stockholders' Equity | |||||
Issuance of stock awards, net of cancellations (in shares) | 1,583 | ||||
Issuance of stock awards, net of cancellations | 0 | $ 2 | (2) | ||
Common stock issued for debt (in shares) | 14,328 | ||||
Common stock issued for debt | 268,779 | $ 14 | 268,765 | ||
Common stock issued for general unsecured claims (in shares) | 104 | ||||
Common stock issued for general unsecured claims | 0 | ||||
Stock-based compensation | 17,912 | 17,912 | |||
Issuance of warrants for general unsecured claims (in shares) | 128 | ||||
Issuance of warrants for general unsecured claims | 0 | $ 119 | (119) | ||
Cash paid for tax withholdings on vested stock awards | (6,730) | (6,730) | |||
Net (loss) income | 47,062 | 47,062 | |||
Ending Balance (in shares) at Dec. 31, 2017 | 35,650 | 6,570 | |||
Ending Balance at Dec. 31, 2017 | 839,940 | $ 36 | $ 88,500 | 1,038,324 | (286,920) |
Increase (Decrease) in Stockholders' Equity | |||||
Issuance of stock awards, net of cancellations (in shares) | 9 | ||||
Issuance of stock awards, net of cancellations | 0 | ||||
Common stock issued for debt | 0 | ||||
Common stock issued for general unsecured claims (in shares) | 28 | ||||
Common stock issued for general unsecured claims | 0 | ||||
Stock-based compensation | 24,276 | 24,276 | |||
Issuance of warrants for general unsecured claims (in shares) | 34 | ||||
Issuance of warrants for general unsecured claims | 0 | $ 16 | (16) | ||
Cash paid for tax withholdings on vested stock awards | (7,420) | (7,420) | |||
Net (loss) income | $ (9,075) | (9,075) | |||
Ending Balance (in shares) at Dec. 31, 2018 | 35,687 | 35,687 | 6,604 | ||
Ending Balance at Dec. 31, 2018 | $ 847,721 | $ 36 | $ 88,516 | 1,055,164 | (295,995) |
Increase (Decrease) in Stockholders' Equity | |||||
Issuance of stock awards, net of cancellations (in shares) | 40 | ||||
Issuance of stock awards, net of cancellations | 0 | ||||
Common stock issued for debt | 0 | ||||
Common stock issued for general unsecured claims (in shares) | 45 | ||||
Common stock issued for general unsecured claims | 0 | ||||
Stock-based compensation | 4,460 | 4,460 | |||
Issuance of warrants for general unsecured claims (in shares) | 55 | ||||
Issuance of warrants for general unsecured claims | 0 | $ 4 | (4) | ||
Cash paid for tax withholdings on vested stock awards | (367) | (367) | |||
Net (loss) income | $ (449,305) | (449,305) | |||
Ending Balance (in shares) at Dec. 31, 2019 | 35,772 | 35,772 | 6,659 | ||
Ending Balance at Dec. 31, 2019 | $ 402,452 | $ 36 | $ 88,520 | $ 1,059,253 | $ (745,357) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Cash Flows [Abstract] | |||
Net (loss) income | $ (449,305) | $ (9,075) | $ 47,062 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities | |||
Provision for doubtful accounts | 16 | (462) | 406 |
Depreciation, depletion and amortization | 158,558 | 139,263 | 131,887 |
Impairment | 409,574 | 4,170 | 4,019 |
Debt issuance costs amortization | 558 | 470 | 430 |
Amortization of discount, net of premium, on debt | 0 | (47) | (330) |
Gain on extinguishment of debt | 0 | (1,151) | 0 |
Write off of debt issuance costs | 142 | 0 | 0 |
(Gain) loss on derivative contracts | (1,094) | 17,155 | (24,090) |
Cash received (paid) on settlement of derivative contracts | 6,266 | (35,325) | 7,260 |
Stock-based compensation | 4,254 | 23,377 | 15,750 |
Other | (187) | (1,571) | 344 |
Changes in operating assets and liabilities increasing (decreasing) cash | |||
Receivables | 15,829 | 16,560 | 115 |
Prepaid expenses | (714) | 2,620 | 127 |
Other current assets | (301) | 170 | 191 |
Other assets and liabilities, net | (610) | (1,754) | 4,186 |
Accounts payable and accrued expenses | (17,217) | (4,257) | (2,199) |
Asset retirement obligations | (4,445) | (4,629) | (3,979) |
Net cash provided by operating activities | 121,324 | 145,514 | 181,179 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Capital expenditures for property, plant and equipment | (191,678) | (187,047) | (219,246) |
Acquisitions of assets | 236 | ||
Acquisitions of assets | (24,764) | (48,312) | |
Proceeds from sale of assets | 1,593 | 28,358 | 21,834 |
Net cash used in investing activities | (189,849) | (183,453) | (245,724) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from borrowings | 211,096 | 10,000 | 0 |
Repayments of borrowings | (153,596) | (46,304) | 0 |
Debt issuance costs | (911) | 0 | (1,488) |
Reduction of financing lease liability | (1,374) | 0 | 0 |
Cash paid for tax withholdings on vested stock awards | (367) | (7,420) | (6,730) |
Net cash provided by (used in) financing activities | 54,848 | (43,724) | (8,218) |
NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | (13,677) | (81,663) | (72,763) |
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 19,645 | 101,308 | 174,071 |
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year | $ 5,968 | $ 19,645 | $ 101,308 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States. Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries, including its proportionate share of the Royalty Trusts. All intercompany accounts and transactions have been eliminated in consolidation. Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; valuation allowances for deferred tax assets; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from those estimates. Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. Restricted Cash. The Company maintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan. Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 5 for further information on the Company’s accounts receivable and allowance for doubtful accounts. Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 4 for further discussion of the Company’s fair value measurements. Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary. Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 6 for further discussion of the Company’s derivatives. Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized gross internal costs of $5.7 million, $8.8 million and $14.8 million during the years ended December 31, 2019, 2018 and 2017, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Under the full cost method of accounting, total capitalized costs of oil and natural gas properties and electrical infrastructure assets, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center. Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. Realization of the carrying value of property and equipment, other than electrical infrastructure assets, is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 9 for further discussion of impairments. Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During the year ended December 31, 2019 the Company capitalized interest of approximately $1.5 million on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. During the year ended December 31, 2018, the Company capitalized an insignificant amount of interest costs and did not capitalize any interest costs in the year ended December 31, 2017, as capital expenditures were largely funded through sources other than debt during these periods. Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt. Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 12 for further discussion of the Company’s asset retirement obligations. Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations. See Note 16 for further information on the Company's accounting policies related to revenues. The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions of $1.6 million and $1.7 million at December 31, 2019 and 2018, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets. Allocation of Share-Based Compensation. Equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations. Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense. Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards, performance share units, warrants, and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 21 for the Company’s earnings per share calculation. Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 13 for discussion of the Company’s commitments and contingencies. Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected. Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces. The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2019 Targa Pipeline Mid-Continent West OK LLC $ 85,780 32.1 % Sinclair Crude Company $ 74,810 28.0 % Plains Marketing, L.P. $ 69,214 25.9 % December 31, 2018 Targa Pipeline Mid-Continent West OK LLC $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % Recent Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, “Leases (Topic 842),” and subsequently issued other associated ASU's related to Topic 842 which supersede Accounting Standards Codification ("ASC") 840 and require lessees to recognize right of use ("ROU") lease assets and liabilities on the balance sheet for long-term leases formerly classified as operating leases under ASC 840, and to disclose key information about leasing arrangements. The Company adopted this ASU on January 1, 2019 using a modified retrospective approach for all ROU leases that existed at the period of adoption and did not restate its comparative periods. See Note 7 for additional discussion of the new leasing standard. Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” and subsequently issued other associated ASU's related to Topic 326, which change how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes," which simplifies various aspects of accounting for income taxes, including requirements related to hybrid tax regimes, the tax basis step-up in goodwill obtained in a transaction that is not a business combination, separate financial statements of entities not subject to tax, the intraperiod tax allocation exception to the incremental approach, ownership changes in investments, interim-period accounting for enacted changes in tax laws, and year-to-date loss limitation in interim-period tax accounting. The standard is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted, and will be applied on a prospective basis. The Company is currently evaluating the effect the guidance will have on its consolidated financial statements. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands): Year Ended December 31, 2019 2018 2017 Supplemental Disclosure of Cash Flow Information Cash paid for interest, net of amounts capitalized $ (2,157) $ (4,045) $ (2,438) Cash received for income taxes $ — $ 4,381 $ 4,348 Supplemental Disclosure of Noncash Investing and Financing Activities Purchase of PP&E in accounts payable $ 4,592 $ 34,235 $ 50,096 Right-of-use assets obtained in exchange for financing lease obligations $ 3,347 $ — $ — Carrying value of properties exchanged $ 5,384 $ — $ — Equity issued for debt $ — $ — $ (268,779) |
Acquisitions and Divestitures o
Acquisitions and Divestitures of Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2019 | |
Acquisitions And Dispositions [Abstract] | |
Acquisitions and Divestitures of Oil and Gas Properties | Acquisitions and Divestitures of Oil and Gas Properties 2019 Acquisitions and Divestitures Nonmonetary transaction. During the third quarter of 2019, the Company transferred its interest in certain proved oil and natural gas properties located in Comanche, Harper and Sumner counties in Kansas along with associated electrical infrastructure and an insignificant amount of accounts receivable with an aggregate estimated fair value of $5.4 million, for an interest in certain other proved oil and natural gas properties located in Comanche, Harper and Barber counties in Kansas. The fair value of the assets given in the transaction approximated their carrying value, therefore no gain or loss was recognized on the transfer. 2018 Divestitures Divestiture of Permian Basin Properties. On November 1, 2018, the Company sold substantially all of its oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced its asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust included 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, the Company no longer has any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale. 2018 Acquisitions Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired an interest in certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which are operated by the Company, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime. 2017 Acquisitions Acquisition of Properties. On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage. 2017 Divestitures 2017 Property Divestitures. In 2017, the Company divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current and non-current assets, accounts payable and accrued expenses and other current liabilities and other long-term obligations included in the consolidated balance sheets approximated fair value at December 31, 2019, and December 31, 2018. Additionally, the carrying amount of debt associated with borrowings outstanding under the credit facility approximates fair value as borrowings bear interest at variable rates. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment classified as assets held for sale and related impairments and nonmonetary transactions, which are calculated using Level 3 inputs, are discussed in Note 8 and Note 9. Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3 Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources ( i.e., supported by little or no market activity). Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company's financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 2 of the hierarchy as of December 31, 2019 and 2018, as described below. Level 2 Fair Value Measurements Commodity Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates. Fair Value - Recurring Measurement Basis The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands): December 31, 2019 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 114 $ — $ — $ 114 $ — $ 114 $ — $ — $ 114 December 31, 2018 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,286 $ — $ — $ 5,286 $ — $ 5,286 $ — $ — $ 5,286 ____________________ (1) Represents the impact of netting assets and liabilities with counterparties where the right of offset exists. Transfers. During the years ended December 31, 2019, 2018 and 2017, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. Fair Value of Non-Financial Assets and Liabilities See Note 9 for discussion of the Company’s impairment valuations. |
Accounts Receivable
Accounts Receivable | 12 Months Ended |
Dec. 31, 2019 | |
Receivables [Abstract] | |
Accounts Receivable | Accounts Receivable A summary of accounts receivable is as follows (in thousands): December 31, 2019 2018 Oil, natural gas and NGL sales $ 22,281 $ 31,780 Joint interest billing 5,165 13,083 Other 2,315 1,935 Total accounts receivable 29,761 46,798 Less: allowance for doubtful accounts (1,117) (1,295) Total accounts receivable, net $ 28,644 $ 45,503 The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Beginning balance $ 1,295 $ 1,274 $ 880 Additions charged to costs and expenses 6 758 397 Deductions(1) (184) (737) (3) Ending balance $ 1,117 $ 1,295 $ 1,274 ____________________ |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives Commodity Derivatives The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. On occasion, the Company has attempted to manage this risk on a portion of its forecasted oil or natural gas production sales through the use of commodity derivative contracts. The Company has not designated any of its derivative contracts as hedges for accounting purposes. All derivative contracts are recorded at fair value with changes in derivative contract fair values recognized as gain or loss on derivative contracts in the condensed consolidated statements of operations. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis, and the commodity derivative contract valuations are adjusted to the mark-to-market valuation on a quarterly basis. The following table summarizes derivative activity for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 (Gain) loss on commodity derivative contracts $ (1,094) $ 17,155 $ (24,090) Cash (received) paid on settlements $ (6,266) $ 35,325 $ (7,260) Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis by commodity type in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2019, the counterparties to the Company’s open commodity derivative contracts consisted of three financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility. The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2019 and 2018 (in thousands): December 31, 2019 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 114 $ — $ 114 $ — $ 114 Total $ 114 $ — $ 114 $ — $ 114 December 31, 2018 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,286 $ — $ 5,286 $ — $ 5,286 Total $ 5,286 $ — $ 5,286 $ — $ 5,286 At December 31, 2019, the Company’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional (Bbl) Weighted Average Fixed Price January 2020 - March 2020 273,000 $ 61.05 Fair Value of Derivatives The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands): December 31, December 31, Type of Contract Balance Sheet Classification 2019 2018 Derivative assets Oil price swaps Derivative contracts - current $ 114 $ — Natural gas price swaps Derivative contracts - current $ — $ 5,286 Total net derivative contracts $ 114 $ 5,286 See Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Leases As discussed in Note 1, the Company adopted ASU 2016-02, "Leases (Topic 842)" on January 1, 2019 using a modified retrospective approach for all ROU leases that existed at the period of adoption and did not restate its comparative periods. Topic 842 provides practical expedients to assist with the transition to the new standard. The Company elected the 'package of practical expedients,' and therefore did not have to reassess prior conclusions about lease identification, lease classification and initial indirect costs. The Company also elected the land easement practical expedient and short-term lease recognition exemption, under which leases with initial terms less than 12 months are not required to be presented on the balance sheet. The Company further elected the practical expedient to combine lease and non-lease components for asset classes including drilling rigs, compressors and various office equipment. The Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Lease liabilities were recognized based on the present value of the lease payments not yet paid over the lease term at January 1, 2019 for existing leases and at the commencement date for any new leases entered into subsequent to January 1, 2019. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. Lease assets are recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Adoption of this standard resulted in additional ROU lease assets and lease liabilities of approximately $2.3 million and $2.4 million, respectively, as of January 1, 2019, which did not materially impact the Company's consolidated financial statements. The difference between the net lease assets and liabilities was recognized as a cumulative-effect adjustment to the opening balance of retained earnings. Operating leases are included in other assets, other current liabilities and other long-term obligations, and finance leases are included in other property, plant and equipment, other current liabilities and other long-term obligations on the accompanying condensed consolidated balance sheet as of December 31, 2019. The Company had no significant capital or operating leases with terms longer than 12 months at December 31, 2018. The Company had operating and financing leases for vehicles, drilling rigs and equipment outstanding during the year ended December 31, 2019, which were not significant to the consolidated financial statements. The components of lease costs recognized for the Company's ROU leases are shown below (in thousands): Year Ended December 31, 2019 Short-term lease cost (1) $ 9,994 Financing lease cost 1,397 Operating lease cost 188 Total lease cost $ 11,579 ___________________ (1) $4.8 million of short-term lease cost was capitalized as part of oil and natural gas properties during the year ended December 31, 2019. Portions of these costs were reimbursed to the Company by other working interest owners. |
Leases | Leases As discussed in Note 1, the Company adopted ASU 2016-02, "Leases (Topic 842)" on January 1, 2019 using a modified retrospective approach for all ROU leases that existed at the period of adoption and did not restate its comparative periods. Topic 842 provides practical expedients to assist with the transition to the new standard. The Company elected the 'package of practical expedients,' and therefore did not have to reassess prior conclusions about lease identification, lease classification and initial indirect costs. The Company also elected the land easement practical expedient and short-term lease recognition exemption, under which leases with initial terms less than 12 months are not required to be presented on the balance sheet. The Company further elected the practical expedient to combine lease and non-lease components for asset classes including drilling rigs, compressors and various office equipment. The Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Lease liabilities were recognized based on the present value of the lease payments not yet paid over the lease term at January 1, 2019 for existing leases and at the commencement date for any new leases entered into subsequent to January 1, 2019. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. Lease assets are recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Adoption of this standard resulted in additional ROU lease assets and lease liabilities of approximately $2.3 million and $2.4 million, respectively, as of January 1, 2019, which did not materially impact the Company's consolidated financial statements. The difference between the net lease assets and liabilities was recognized as a cumulative-effect adjustment to the opening balance of retained earnings. Operating leases are included in other assets, other current liabilities and other long-term obligations, and finance leases are included in other property, plant and equipment, other current liabilities and other long-term obligations on the accompanying condensed consolidated balance sheet as of December 31, 2019. The Company had no significant capital or operating leases with terms longer than 12 months at December 31, 2018. The Company had operating and financing leases for vehicles, drilling rigs and equipment outstanding during the year ended December 31, 2019, which were not significant to the consolidated financial statements. The components of lease costs recognized for the Company's ROU leases are shown below (in thousands): Year Ended December 31, 2019 Short-term lease cost (1) $ 9,994 Financing lease cost 1,397 Operating lease cost 188 Total lease cost $ 11,579 ___________________ (1) $4.8 million of short-term lease cost was capitalized as part of oil and natural gas properties during the year ended December 31, 2019. Portions of these costs were reimbursed to the Company by other working interest owners. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment consists of the following (in thousands): December 31, 2019 2018 Oil and natural gas properties Proved $ 1,484,359 $ 1,269,091 Unproved 24,603 60,152 Total oil and natural gas properties 1,508,962 1,329,243 Less accumulated depreciation, depletion and impairment (1,129,622) (580,132) Net oil and natural gas properties capitalized costs 379,340 749,111 Land 4,400 4,400 Electrical infrastructure 126,482 131,176 Non-oil and natural gas equipment 12,665 13,458 Buildings and structures 77,148 77,148 Financing Leases 2,109 — Total 222,804 226,182 Less accumulated depreciation and amortization (34,201) (25,344) Other property, plant and equipment, net 188,603 200,838 Total property, plant and equipment, net $ 567,943 $ 949,949 The average rates used for depreciation and depletion of oil and natural gas properties were $12.28 per Boe in 2019, $10.32 per Boe in 2018 and $7.92 per Boe in 2017. See Note 9 for discussion of impairment of other property, plant and equipment. Costs Excluded from Amortization The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2019 (in thousands): Year Cost Incurred Total 2019 2018 2017 2016 and Prior Property acquisition $ 23,973 $ 2,653 $ 2,353 $ 4,280 $ 14,687 Exploration 630 10 16 564 40 Total costs incurred $ 24,603 $ 2,663 $ 2,369 $ 4,844 $ 14,727 three five |
Impairment
Impairment | 12 Months Ended |
Dec. 31, 2019 | |
Asset Impairment Charges [Abstract] | |
Impairment | Impairment The Company assesses the need to impair its oil and gas properties during its quarterly full cost pool ceiling limitation calculation. The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. The full cost pool ceiling limitation and estimated fair values of drilling, midstream, and other assets were determined in accordance with the policies discussed in Note 1. Impairment for the years ended December 31, 2019, 2018 and 2017 consists of the following (in thousands): Year Ended December 31, 2019 2018 2017 Full cost pool ceiling limitation(1) $ 409,574 $ — $ — Drilling assets(2) — 22 4,019 Midstream assets(3) — 4,148 — $ 409,574 $ 4,170 $ 4,019 ____________________ (1) Impairment recorded in the year ended December 31, 2019 largely resulted from a decrease in the trailing twelve-month weighted average SEC prices for oil and natural gas prices in 2019, lower NGL prices, increases in expected operating expenses, and other less significant inputs. See Note 22 for additional discussion of our oil and gas producing properties. (2) Impairment recorded in the years ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. |
Accounts Payable and Accrued Ex
Accounts Payable and Accrued Expenses | 12 Months Ended |
Dec. 31, 2019 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Expenses | Accounts Payable and Accrued Expenses Accounts payable and accrued expenses consist of the following (in thousands): December 31, 2019 2018 Accounts payable and other accrued expenses $ 29,423 $ 62,733 Production payable 22,530 28,253 Payroll and benefits 7,021 12,891 Taxes payable 4,988 5,350 Drilling advances 514 2,031 Accrued interest 461 539 Total accounts payable and accrued expenses $ 64,937 $ 111,797 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt consists of the following (in thousands): December 31, 2019 2018 Credit facility $ 57,500 $ — Total debt 57,500 — Less: current maturities of long-term debt — — Long-term debt $ 57,500 $ — Credit Facility. On June 21, 2019, the Company amended and restated its existing $600.0 million reserve-based revolving credit facility. The initial borrowing base of the restated credit facility was $300.0 million, which was reduced to $225.0 million during the semi-annual redetermination concluded in November 2019. The next borrowing base redetermination is scheduled for April 2020. The restatement extended the credit facility maturity date to April 1, 2021 from March 31, 2020. The Company has $57.5 million outstanding under the credit facility at December 31, 2019, and $2.9 million in outstanding letters of credit, which reduce availability under the restated credit facility on a dollar-for-dollar basis. The interest rate on outstanding borrowings under the restated credit facility was determined by a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 2.00% to 3.00% per annum, or (b) the base rate plus an applicable margin that varies from 1.00% to 2.00% per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50% on any available portion of the credit facility. During the year ended December 31, 2019, the weighted average interest rate paid for borrowings outstanding under both the previously outstanding credit facility and the amended and restated credit facility was approximately 4.7%. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. The restated credit facility is secured by (i) first-priority mortgages on at least 85% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing). The restated facility includes events of default and certain customary affirmative and negative covenants. The Company is required to maintain certain financial covenants including (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. As of December 31, 2019, the Company was in compliance with all applicable covenants and had a consolidated total net leverage ratio of 0.38 and consolidated interest coverage ratio of 37.89. The credit facility previously outstanding from February 10, 2017 through June 21, 2019 had an initial borrowing base of $425.0 million, which was reduced to $350.0 million during a borrowing base redetermination in October 2018. The previously outstanding credit facility had materially similar terms and covenants to the current amended and restated credit facility, but was secured by first-priority mortgages on at least 95% of the PV-9 valuation of the Company's proved reserves and interest was calculated based on a pricing grid tied to the borrowing base utilization rate of (a) LIBOR plus an applicable margin that varied from 3.00% to 4.00% per annum, or (b) the base rate plus an applicable margin that varied from 2.00% to 3.00% per annum. The Company incurred an immaterial amount of interest expense on the previously outstanding credit facility during the years ended December 31, 2018 and 2017. Building Note. In February 2018, the Company fully repaid the Building Note in the amount of $36.3 million, which was comprised of an initial principal amount of $35.0 million and $1.3 million in in-kind interest costs that were previously added to the principal. An unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the condensed consolidated statement of operations for the year ended December 31, 2018 in connection with the repayment. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands): Year Ended December 31, 2019 2018 2017 Beginning balance $ 60,064 $ 77,544 $ 106,481 Liability incurred upon acquiring and drilling wells 2,771 7,079 1,336 Revisions in estimated cash flows(1) 12,208 870 (28,565) Liability settled or disposed in current period(2) (5,379) (31,967) (11,308) Accretion 5,352 6,538 9,600 Ending balance 75,016 60,064 77,544 Less: current portion 22,119 25,393 41,017 Asset retirement obligations, net of current $ 52,897 $ 34,671 $ 36,527 ____________________ (1) Revisions for the years ended December 31, 2019, 2018 and 2017 relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of the Company's various future commitments and contingencies as of December 31, 2019. The commitments and contingencies under these arrangements are not recorded in the accompanying consolidated balance sheets. At December 31, 2019 the Company's only material commitment in each of the next five years and beyond is its asset retirement obligations. See Note 12 for additional discussions. Litigation and Claims. As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016. Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”): • In re SandRidge Energy, Inc. Securities Litigation , Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma; and • Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al ., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma The lead plaintiffs in both In re SandRidge Energy, Inc. Securities Litigation and Lanier Trust assert claims on behalf of themselves and (i) in In re SandRidge Energy, Inc. Securities Litigation , a class of all purchasers of SandRidge common stock from February 24, 2011 and November 8, 2012 under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, and (ii) in Lanier Trust , a putative class of purchasers of SandRidge Mississippian Trust I and SandRidge Mississippian Trust II common units between April 7, 2011 and November 8, 2012 under Sections 11, 12(a)(2), and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, both based on allegations that defendants, which include certain former officers of the Company and the SandRidge Mississippian Trust I, made misrepresentations or omissions concerning various topics including the performance of wells operated by the Company in the Mississippian region. Discovery in each of the Cases closed on June 19, 2019. Following a hearing on class certification in each of the Cases on September 6, 2019, the court granted class certification in In re SandRidge Energy, Inc. Securities Litigation on September 30, 2019. The motion for class certification in Lanier Trust remains pending. In each of the Cases, lead plaintiffs seek to recover unspecified damages, interest, costs and expenses incurred in the litigation on behalf of themselves and class members. Although the claims against the Company in each Case have been discharged pursuant to the Plan, the Company remains a nominal defendant in each of the Cases to the extent necessary to allow recovery from applicable insurance policies or proceeds. In addition, the Company owes indemnity obligations and/or the obligation to advance legal fees, to certain former officers who remain as defendants in each action. The Company may also be contractually obligated to indemnify the SandRidge Mississippian Trust I against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses, arising out of the Cases, and such indemnification is not covered by insurance. In light of the status of the Cases, and the facts, circumstances and legal theories relating thereto, the Company is not able to determine the likelihood of an outcome in either case or provide an estimate of any reasonably possible loss or range of possible loss related thereto. However, considering the erosion of insurance coverage available to the Company, such losses, if incurred, could be material. The Company has not established any liabilities relating to the Cases and believes that the plaintiffs’ claims are without merit. The Company intends to continue to vigorously defend against the Cases in its capacity as a nominal defendant. In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business, none of which is deemed to be individually material at this time. Due to the inherent uncertainty of litigation, however, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company’s income tax (benefit) provision consisted of the following components (in thousands): Year Ended December 31, 2019 2018 2017 Current Federal $ — $ (33) $ (8,719) State — (38) (30) — (71) (8,749) Deferred Federal — — — State — — — — — — Total (benefit) provision $ — $ (71) $ (8,749) A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Computed at federal statutory rate $ (94,354) $ (1,921) $ 13,409 State taxes, net of federal benefit (20,500) 119 (284) Non-deductible expenses 137 849 1,711 Stock-based compensation 602 1,874 1,109 Discharge of debt and other reorganization related items — 206 1,018 Return to provision adjustments (1) (6,096) (1,292) 341,681 Impact of legislative changes — — 243,801 Release of valuation allowance — — (8,719) Change in valuation allowance 120,211 132 (602,452) Other — (38) (23) Total (benefit) provision $ — $ (71) $ (8,749) ____________________ (1) The adjustment for the period ended December 31, 2017, primarily related to the Company’s decision to file its 2016 income tax returns using an alternate method than previously estimated with respect to its Chapter 11 related transactions. Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. During the year ended December 31, 2017, the Company reduced the valuation allowance associated with deferred tax assets related to alternative minimum tax ("AMT") credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. As a result of the significant weight placed on the Company’s cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its remaining net deferred tax asset at December 31, 2017, December 31, 2018 and December 31, 2019. Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands): December 31, 2019 December 31, 2018 Deferred tax liabilities Investments(1) $ 109,289 $ 112,343 Derivative contracts 29 1,128 Total deferred tax liabilities 109,318 113,471 Deferred tax assets Property, plant and equipment 300,704 267,865 Net operating loss carryforwards 383,418 302,190 Tax credits and other carryforwards 34,148 35,640 Asset retirement obligations 18,747 15,016 Other 2,290 3,816 Total deferred tax assets 739,307 624,527 Valuation allowance (629,989) (511,056) Net deferred tax liability $ — $ — ____________________ (1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. The "Tax Cuts and Jobs Act" (the "TCJA") enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses ("NOLs"), and limitations on the deduction of interest expense and executive compensation. Based on our analysis of the TCJA and guidance currently available we recorded income tax expense of approximately $243.8 million in the period ended December 31, 2017, which was completely offset by a decrease in the corresponding valuation allowance. The provisional amount primarily related to the remeasurement of our gross deferred tax assets and liabilities existing at December 31, 2017 at the appropriate tax rate expected to exist at the time of their reversal. We completed our analysis of the impact of the TCJA and recorded an immaterial adjustment to income tax expense in the year ended December 31, 2018, which was completely offset by an increase in the corresponding valuation allowance. Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 during 2016 that subjected certain of the Company’s tax attributes, including net operating losses ("NOLs"), to an IRC Section 382 limitation. This limitation has not resulted in cash taxes for any period subsequent to the ownership change. Since the 2016 ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company's ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company's stock including those outside of the Company's control could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation. As of December 31, 2019, the Company had approximately $1.4 billion of federal NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.4 billion of federal NOL carryforwards, $0.8 billion expire during the years 2025 through 2037, while $0.6 billion do not have an expiration date. Additionally, the Company had federal tax credits in excess of $32.0 million which begin expiring in 2029. The Company did not have unrecognized tax benefits at December 31, 2019 or 2018. three five |
Equity
Equity | 12 Months Ended |
Dec. 31, 2019 | |
Equity [Abstract] | |
Equity | Equity Common Stock and Performance Share Units. At December 31, 2019, the Company had 35.8 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.2 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. The Company also had restricted stock awards and an immaterial amount of performance share units and stock options outstanding at December 31, 2019 as discussed further in Note 17. Warrants. Since the fourth quarter of 2016, the Company has issued approximately 4.7 million Series A warrants and 2.0 million Series B warrants to certain holders of general unsecured claims as defined in the Plan. These warrants are exercisable until October 4, 2022 for one share of common stock per warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the warrants. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired. Year Ended December 31, 2019 2018 2017 Number of shares withheld for taxes 56 495 349 Value of shares withheld for taxes $ 367 $ 7,420 $ 6,730 |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | Revenues The Company adopted ASC 606 on January 1, 2018, using the modified retrospective method for all contracts outstanding on that date. Adoption of ASC 606 had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date. The following table disaggregates the Company’s revenue by source for the years ended December 31, 2019, 2018, and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Oil $ 186,360 $ 214,651 $ 202,539 NGL 35,598 67,111 61,322 Natural gas 44,146 66,964 92,349 Other 741 669 1,089 Total revenues $ 266,845 $ 349,395 $ 357,299 Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs. In accordance with the contracts governing these sales, performance obligations to customers are satisfied and revenues are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis. Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production, ad valorem, and other taxes expense in the consolidated statements of operations. Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2019 and 2018 the Company had revenues receivable of $22.3 million and $31.8 million, respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2019. |
Share Based Compensation
Share Based Compensation | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Share-Based Compensation | Share-Based Compensation Share-Based Compensation Omnibus Incentive Plan. The Omnibus Incentive Plan became effective on October 4, 2016 and authorizes the issuance of up to 4.6 million shares of SandRidge common stock. Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock, as well as certain cash-based awards. At December 31, 2019, the Company had restricted stock awards and immaterial amounts of performance share units and stock options outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur. Restricted Stock Awards. The Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Vesting for certain restricted stock awards was accelerated in connection with executive terminations and reductions in force in the first quarter of 2018 and second quarter of 2019. Additionally, certain restricted stock awards vested in June 2018 as a result of the accelerated vesting event related to the change in the composition of the Board resulting from the 2018 annual meeting discussed in Note 19. The Company granted additional restricted stock awards in the second half of 2018. Outstanding restricted shares at December 31, 2019 will generally vest over either a one three The following table presents a summary of the Company’s unvested restricted stock awards: Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at December 31, 2016 1,407 $ 24.32 Granted 671 $ 19.97 Vested (827) $ 23.23 Forfeited / Canceled (146) $ 23.52 Unvested restricted shares outstanding at December 31, 2017 1,105 $ 22.62 Granted 370 $ 16.00 Vested (1,066) $ 22.63 Forfeited / Canceled (44) $ 21.04 Unvested restricted shares outstanding at December 31, 2018 365 $ 16.07 Granted 93 $ 8.06 Vested (1) (210) $ 16.29 Forfeited / Canceled (15) $ 16.25 Unvested restricted shares outstanding at December 31, 2019 233 $ 12.66 ____________________ (1) The aggregate intrinsic value of restricted stock that vested during 2019 was approximately $1.5 million based on the stock price at the time of vesting. Performance Share Units. In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 19 and were settled in shares of the Company's common stock with one share of common stock being issued per performance share unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company's performance share units: Number of Fair Value per Unit at December 31, 2019 (In thousands) Unvested performance share units outstanding at December 31, 2016 — Granted 199 Vested — Forfeited / Canceled (16) Unvested performance share units outstanding at December 31, 2017 183 Granted 111 Vested (177) Forfeited / Canceled (6) Unvested performance share units outstanding at December 31, 2018 111 Granted — Vested (19) Forfeited / Canceled — Unvested performance share units outstanding at December 31, 2019 92 $ 20.41 Incentive-Based Compensation Performance Units. In October 2016, the Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 19 and were paid at the issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a summary of the Company's performance units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance units outstanding at December 31, 2016 87 Granted — Vested (32) Forfeited / Canceled (6) Unvested performance units outstanding at December 31, 2017 49 Granted — Vested (48) Forfeited / Canceled (1) Unvested performance units outstanding at December 31, 2018 — $ — The following tables summarize the Company's share and incentive-based compensation for the years ended December 31, 2019, 2018, and 2017 (in thousands): Recurring Compensation Expense(1) Executive Terminations(2) Reduction in Force(2) Accelerated Vesting(3) Total Year Ended December 31, 2019 Equity-classified awards: Restricted stock awards $ 2,526 $ 197 $ 500 $ — $ 3,223 Performance share units 282 281 — — 563 Stock options 661 12 — — 673 Total share-based compensation expense 3,469 490 500 — 4,459 Less: Capitalized compensation expense (204) — — — (204) Share and incentive-based compensation expense, net $ 3,265 $ 490 $ 500 $ — $ 4,255 Year Ended December 31, 2018 Equity-classified awards: Restricted stock awards $ 4,735 $ 8,140 $ 3,777 $ 5,181 $ 21,833 Performance share units 619 1,056 158 610 2,443 Total share-based compensation expense 5,354 9,196 3,935 5,791 24,276 Liability-classified awards: Performance units 756 2,151 558 1,309 4,774 Total share and incentive-based compensation expense 6,110 11,347 4,493 7,100 29,050 Less: Capitalized compensation expense (482) — — (555) (1,037) Share and incentive-based compensation expense, net $ 5,628 $ 11,347 $ 4,493 $ 6,545 $ 28,013 Year Ended December 31, 2017 Equity-classified awards: Restricted stock awards $ 14,731 $ 1,825 $ — $ — $ 16,556 Performance share units 1,356 — — — 1,356 Total share-based compensation expense 16,087 1,825 — — 17,912 Liability-classified awards: Performance units 2,574 — — — 2,574 Total share and incentive-based compensation expense 18,661 1,825 — — 20,486 Less: Capitalized compensation expense (2,521) — — — (2,521) Share and incentive-based compensation expense, net $ 16,140 $ 1,825 $ — $ — $ 17,965 ____________________ (1) Recorded in general and administrative expense in the accompanying consolidated statements of operations. (2) Recorded in employee termination benefits in the accompanying consolidated statements of operations. (3) Recorded in accelerated vesting of employment compensation in the accompanying consolidated statements of operations. |
Incentive and Deferred Compensa
Incentive and Deferred Compensation Plans | 12 Months Ended |
Dec. 31, 2019 | |
Compensation Related Costs [Abstract] | |
Incentive and Deferred Compensation Plans | Incentive and Deferred Compensation Plans Annual Incentive Plan. The Annual Incentive Plan ("AIP") incorporates quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2018 and 2017 performance years. Incentive bonus awards for 2019 will be provided at the discretion of the Board of Directors and will be paid quarterly during 2020. Payout percentages ranged from 0% to 200% of specified target levels based on actual performance in 2018 and 2017. As of December 31, 2019, the Company had accrued approximately $2.7 million for the 2019 AIP. Payment of $7.1 million was made in the first quarter of 2019 for the 2018 performance year. 401(k) Plan. The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by IRS. For the years ended December 31, 2019, 2018, and 2017, the Company made matching contributions to the plan equal to 100% on the first 10% of employee deferred wages, excluding incentive compensation, totaling $2.2 million, $2.8 million, and $3.6 million, respectively. The decrease in contributions is due primarily to reductions in force that occ urred in each of those years. Participants in the plan are immediately 100% vested in the discretionary employee contributions and related earnings on those contributions. The Company's matching contributions and related earnings vest based on years of service, with full vesting occurring on the four |
Proxy Contest
Proxy Contest | 12 Months Ended |
Dec. 31, 2019 | |
Other Income and Expenses [Abstract] | |
Proxy Contest | Proxy Contest In the second quarter of 2018, the Company engaged in a proxy contest with its largest shareholder, Carl C. Icahn and certain affiliated entities, which resulted in the election of a majority of non-incumbent directors to the Company's Board of Directors. As confirmed by general counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest resulted in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 17. The Company incurred legal, consulting and advisory fees of $7.1 million related to the proxy contest during the year ended December 31, 2018. |
Employee Termination Benefits
Employee Termination Benefits | 12 Months Ended |
Dec. 31, 2019 | |
Postemployment Benefits [Abstract] | |
Employee Termination Benefits | Employee Termination Benefits The following table presents a summary of employee termination benefits for the years ended December 31, 2019, 2018, and 2017 (in thousands): Cash Share-Based Compensation (6) Number of Shares Total Employee Termination Benefits Year Ended December 31, 2019 Executive Employee Termination Benefits(1) $ 1,194 $ 490 37 $ 1,684 Other Employee Termination Benefits(2) 2,608 500 44 3,108 $ 3,802 $ 990 81 $ 4,792 Year Ended December 31, 2018 Executive Employee Termination Benefits(3) $ 11,945 $ 9,196 554 $ 21,141 Other Employee Termination Benefits(4) 7,581 3,935 209 11,516 $ 19,526 $ 13,131 763 $ 32,657 Year Ended December 31, 2017 Executive Employee Termination Benefits(5) $ 2,500 $ 1,825 96 $ 4,325 Other Employee Termination Benefits 490 — — 490 $ 2,990 $ 1,825 96 $ 4,815 ____________________ (1) On December 12, 2019, the Company's then current CEO, Paul McKinney, separated employment from the Company, and on June 14, 2019, the Company’s then current Executive Vice President, General Counsel and Corporate Secretary, Philip Warman, separated employment from the Company. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2019. (2) As a result of a reduction in workforce in the second quarter of 2019, certain employees received termination benefits including cash severance and accelerated share-based compensation upon separation of service from the Company. (3) On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018. (4) As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. (5) Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert. (6) Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reductions in workforce in 2019 and 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit. See Note 17 for additional discussion of the Company’s share-based compensation awards. |
(Loss) Earnings per Share
(Loss) Earnings per Share | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
(Loss) Earnings per Share | (Loss) Earnings per Share The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share: Net (Loss) Income Weighted Average Shares (Loss) Earnings Per Share (In thousands, except per share amounts) Year Ended December 31, 2019 Basic loss per share $ (449,305) 35,427 $ (12.68) Effect of dilutive securities Restricted stock awards(1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (449,305) 35,427 $ (12.68) Year Ended December 31, 2018 Basic loss per share $ (9,075) 35,057 $ (0.26) Effect of dilutive securities Restricted stock awards(1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (9,075) 35,057 $ (0.26) Year Ended December 31, 2017 Basic earnings per share $ 47,062 32,442 $ 1.45 Effect of dilutive securities Restricted stock awards — 221 Performance share units(2) — — Warrants(2) — — Diluted earnings per share $ 47,062 32,663 $ 1.44 ____________________ (1) No incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2019 and 2018, as their effect was antidilutive under the treasury stock method. (2) No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method. |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) | Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves. Capitalized Costs Related to Oil and Natural Gas Producing Activities The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands): December 31, 2019 2018 2017 Oil and natural gas properties Proved $ 1,484,359 $ 1,269,091 $ 1,056,806 Unproved 24,603 60,152 100,884 Total oil and natural gas properties 1,508,962 1,329,243 1,157,690 Less accumulated depreciation, depletion and impairment (1,129,622) (580,132) (460,431) Net oil and natural gas properties capitalized costs $ 379,340 $ 749,111 $ 697,259 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands): Year Ended December 31, 2019 2018 2017 Acquisitions of properties Proved $ (210) $ 30,641 $ 7,092 Unproved 2,653 4,197 91,139 Exploration 2,900 1,940 8,850 Development 156,210 158,361 187,264 Total cost incurred $ 161,553 $ 195,139 $ 294,345 Results of Operations for Oil and Natural Gas Producing Activities The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings. Year Ended December 31, 2019 2018 2017 Revenues $ 266,104 $ 348,726 $ 356,210 Expenses Production costs 110,711 112,173 116,372 Depreciation and depletion 146,874 127,281 118,035 Impairment 409,574 — — Total expenses 667,159 239,454 234,407 Income (loss) before income taxes (401,055) 109,272 121,803 Income tax (benefit) expense (1) (105,477) 28,520 47,722 Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) $ (295,578) $ 80,752 $ 74,081 ____________________ (1) Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits. Oil, Natural Gas and NGL Reserve Quantities Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of mandated economic assumptions; and • the judgment of the personnel preparing the estimates. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion. The following table represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Over 90% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs for over 90% of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2019, 2018 and 2017. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates. The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change. 2019 Activity . Proved reserves decreased from 160.2 MMBoe at December 31, 2018 to 89.9 MMBoe at December 31, 2019, primarily as a result of downward revisions of 50.9 MMBoe associated with the decrease in year-end SEC prices for oil and natural gas consisting of (i) 39.8 MMBoe from downgrading PUDs, and (ii) 11.1 MMBoe from remaining proved reserves. The Company also recorded a decrease of 10.9 MMBoe attributable to increased commodity price differentials, and a decrease of 3.2 MMBoe attributable to well performance. These reductions were partially offset by a 12.6 MMBoe increase associated with converting undeveloped well locations from SRLs to planned XRLs as well as reduced future estimated development capital on these undeveloped locations. 2018 Activity. Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin. 2017 Activity. During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance. The summary below presents changes in the Company’s estimated reserves. Oil NGL Natural Gas Total (MBbls) (MBbls) (MMcf)(1) MBoe Proved developed and undeveloped reserves As of December 31, 2016 52,884 33,607 464,782 163,955 Revisions of previous estimates 804 2,628 44,679 10,879 Acquisitions of new reserves 18 70 683 202 Extensions and discoveries 12,446 1,914 30,080 19,373 Sales of reserves in place (204) (529) (7,055) (1,909) Production (4,157) (3,376) (44,237) (14,906) As of December 31, 2017 61,791 34,314 488,932 177,594 Revisions of previous estimates (2,316) (8,952) (131,518) (33,188) Acquisitions of new reserves 2,146 4,131 54,436 15,350 Extensions and discoveries 11,148 2,320 35,185 19,332 Sales of reserves in place (5,273) (809) (2,969) (6,577) Production (3,477) (2,829) (36,175) (12,335) As of December 31, 2018 64,019 28,175 407,891 160,176 Revisions of previous estimates (25,530) (9,277) (142,239) (58,514) Extensions and discoveries 635 94 2,127 1,084 Sales of reserves in place (297) (223) (2,308) (905) Production (3,519) (2,910) (33,164) (11,956) As of December 31, 2019 35,308 15,859 232,307 89,885 Proved developed reserves As of December 31, 2017 25,845 29,922 407,988 123,765 As of December 31, 2018 18,693 22,302 307,845 92,303 As of December 31, 2019 14,078 14,532 200,853 62,086 Proved undeveloped reserves As of December 31, 2017 35,946 4,392 80,944 53,829 As of December 31, 2018 45,326 5,873 100,046 67,873 As of December 31, 2019 21,230 1,327 31,454 27,799 _________________ (1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. Standardized Measure of Discounted Future Net Cash Flows (Unaudited) The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows: • the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions; • pricing is applied based upon SEC prices at December 31, 2019, 2018, and 2017 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: At December 31, 2019 2018 2017 Oil (per Bbl) $ 50.63 $ 60.86 $ 48.47 NGL (per Bbl) $ 12.45 $ 25.62 $ 20.28 Natural gas (per Mcf) $ 1.16 $ 1.77 $ 1.90 • future development and production costs are determined based upon actual cost at year-end; • the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and • a discount factor of 10% per year is applied annually to the future net cash flows. The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands). December 31, 2019 2018 2017 Future cash inflows from production $ 2,254,530 $ 5,339,265 $ 4,621,615 Future production costs (1,028,695) (1,996,689) (1,837,852) Future development costs(1) (536,081) (1,170,113) (966,203) Future income tax expenses (2) — — (107) Undiscounted future net cash flows 689,754 2,172,463 1,817,453 10% annual discount (325,464) (1,126,860) (1,068,159) Standardized measure of discounted future net cash flows $ 364,290 $ 1,045,603 $ 749,294 ____________________ (1) Includes abandonment costs. (2) The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards. The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands): Year Ended December 31, 2019 2018 2017 Beginning present value $ 1,045,603 $ 749,294 $ 438,364 Changes during the year Revenues less production (155,772) (236,553) (239,838) Net changes in prices, production and other costs (491,035) 316,095 347,458 Development costs incurred 90,591 80,050 35,517 Net changes in future development costs(1) 450,162 (11,483) (64,484) Extensions and discoveries 11,921 102,961 112,556 Revisions of previous quantity estimates(1) (478,238) (91,038) 26,697 Accretion of discount 101,778 70,576 37,226 Net change in income taxes — 56 23 Purchases of reserves in-place — 35,713 454 Sales of reserves in-place (3,331) (2,029) (2,977) Timing differences and other(2) (207,389) 31,961 58,298 Net change for the year (681,313) 296,309 310,930 Ending present value(3) $ 364,290 $ 1,045,603 $ 749,294 ____________________ (1) The change in estimated future development costs and revisions of previous quantity estimates primarily reflect a decrease in planned PUD development due to declining year end SEC prices for oil and natural gas. (2) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. (3) Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices. |
Quarterly Financial Results (Un
Quarterly Financial Results (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Results (Unaudited) | Quarterly Financial Results (Unaudited) The Company’s operating results for each quarter of 2019 and 2018 are summarized below (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter 2019 Total revenues $ 73,236 $ 75,388 $ 58,369 $ 59,852 Loss from operations(1)(2)(3) $ (4,261) $ (12,556) $ (181,707) $ (248,243) Net loss(1)(2)(3) $ (5,277) $ (13,284) $ (181,602) $ (249,142) Loss applicable per share to SandRidge Energy, Inc. common stockholders Basic $ (0.15) $ (0.38) $ (5.12) $ (7.01) Diluted $ (0.15) $ (0.38) $ (5.12) $ (7.01) ____________________ (1) Includes loss (gain) on derivative contracts of $0.2 million, $(1.8) million and $0.5 million for the first, third, and fourth quarters, respectively. (2) Includes employee termination benefits of $4.5 million and $0.3 million for the second quarter and fourth quarters, respectively. (3) Includes full cost ceiling limitation impairments of $165.5 million and $244.1 million for the third and fourth quarters, respectively. First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenues $ 87,128 $ 79,462 $ 97,660 $ 85,145 (Loss) income from operations(1)(2) $ (41,967) $ (33,685) $ 12,430 $ 52,847 Net (loss) income(1)(2) $ (40,894) $ (34,074) $ 11,715 $ 54,178 (Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders Basic $ (1.18) $ (0.97) $ 0.33 $ 1.53 Diluted $ (1.18) $ (0.97) $ 0.33 $ 1.53 ____________________ (1) Includes loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively. (2) Includes employee termination benefits of $31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events On February 4, 2020, the Company issued Workers Adjustment and Retraining Notification (WARN) Act notices to approximately 63 of its 120 Oklahoma City based employees as a result of its workforce reduction at its corporate headquarters. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Business | Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States. |
Principles of Consolidation | Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries, including its proportionate share of the Royalty Trusts. All intercompany accounts and transactions have been eliminated in consolidation. |
Reclassifications | Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations. |
Use of Estimates | Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; valuation allowances for deferred tax assets; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from those estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. |
Restricted Cash | Restricted Cash. The Company |
Accounts Receivable, Net | Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 5 for further information on the Company’s accounts receivable and allowance for doubtful accounts. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 4 for further discussion of the Company’s fair value measurements. |
Fair Value of Non-financial Assets and Liabilities | Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary. |
Derivative Financial Instruments | Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 6 for further discussion of the Company’s derivatives. |
Oil and Natural Gas Operations | Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized gross internal costs of $5.7 million, $8.8 million and $14.8 million during the years ended December 31, 2019, 2018 and 2017, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Under the full cost method of accounting, total capitalized costs of oil and natural gas properties and electrical infrastructure assets, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center. |
Property, Plant and Equipment, Net | Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. Realization of the carrying value of property and equipment, other than electrical infrastructure assets, is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 9 for further discussion of impairments. |
Capitalized Interest | Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. |
Debt Issuance Costs | Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt. |
Asset Retirement Obligations | Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 12 for further discussion of the Company’s asset retirement obligations. |
Revenue Recognition | Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations. See Note 16 for further information on the Company's accounting policies related to revenues. The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions of $1.6 million and $1.7 million at December 31, 2019 and 2018, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets. Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs. In accordance with the contracts governing these sales, performance obligations to customers are satisfied and revenues are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis. Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production, ad valorem, and other taxes expense in the consolidated statements of operations. Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2019 and 2018 the Company had revenues receivable of $22.3 million and $31.8 million, respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2019. |
Allocation of Share-Based Compensation | Allocation of Share-Based Compensation. Equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations. |
Income Taxes | Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense. |
Earnings per Share | Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards, performance share units, warrants, and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 21 for the Company’s earnings per share calculation. |
Commitments and Contingencies | Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 13 for discussion of the Company’s commitments and contingencies. |
Concentration of Risk | Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected. Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces. The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2019 Targa Pipeline Mid-Continent West OK LLC $ 85,780 32.1 % Sinclair Crude Company $ 74,810 28.0 % Plains Marketing, L.P. $ 69,214 25.9 % December 31, 2018 Targa Pipeline Mid-Continent West OK LLC $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % |
Recent Accounting Pronouncements | Recent Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, “Leases (Topic 842),” and subsequently issued other associated ASU's related to Topic 842 which supersede Accounting Standards Codification ("ASC") 840 and require lessees to recognize right of use ("ROU") lease assets and liabilities on the balance sheet for long-term leases formerly classified as operating leases under ASC 840, and to disclose key information about leasing arrangements. The Company adopted this ASU on January 1, 2019 using a modified retrospective approach for all ROU leases that existed at the period of adoption and did not restate its comparative periods. See Note 7 for additional discussion of the new leasing standard. Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” and subsequently issued other associated ASU's related to Topic 326, which change how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes," which simplifies various aspects of accounting for income taxes, including requirements related to hybrid tax regimes, the tax basis step-up in goodwill obtained in a transaction that is not a business combination, separate financial statements of entities not subject to tax, the intraperiod tax allocation exception to the incremental approach, ownership changes in investments, interim-period accounting for enacted changes in tax laws, and year-to-date loss limitation in interim-period tax accounting. The standard is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted, and will be applied on a prospective basis. The Company is currently evaluating the effect the guidance will have on its consolidated financial statements. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies Summary (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Schedules of Concentration of Risk | The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands): Sales % of Revenue December 31, 2019 Targa Pipeline Mid-Continent West OK LLC $ 85,780 32.1 % Sinclair Crude Company $ 74,810 28.0 % Plains Marketing, L.P. $ 69,214 25.9 % December 31, 2018 Targa Pipeline Mid-Continent West OK LLC $ 126,548 36.2 % Plains Marketing, L.P. $ 102,182 29.2 % Sinclair Crude Company $ 62,623 17.9 % December 31, 2017 Targa Pipeline Mid-Continent West OK LLC $ 144,583 40.5 % Plains Marketing, L.P. $ 117,927 33.0 % |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands): Year Ended December 31, 2019 2018 2017 Supplemental Disclosure of Cash Flow Information Cash paid for interest, net of amounts capitalized $ (2,157) $ (4,045) $ (2,438) Cash received for income taxes $ — $ 4,381 $ 4,348 Supplemental Disclosure of Noncash Investing and Financing Activities Purchase of PP&E in accounts payable $ 4,592 $ 34,235 $ 50,096 Right-of-use assets obtained in exchange for financing lease obligations $ 3,347 $ — $ — Carrying value of properties exchanged $ 5,384 $ — $ — Equity issued for debt $ — $ — $ (268,779) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on Recurring Basis | The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands): December 31, 2019 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 114 $ — $ — $ 114 $ — $ 114 $ — $ — $ 114 December 31, 2018 Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value Level 1 Level 2 Level 3 Assets Commodity derivative contracts $ — $ 5,286 $ — $ — $ 5,286 $ — $ 5,286 $ — $ — $ 5,286 ____________________ |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Receivables [Abstract] | |
Summary of Accounts Receivable | A summary of accounts receivable is as follows (in thousands): December 31, 2019 2018 Oil, natural gas and NGL sales $ 22,281 $ 31,780 Joint interest billing 5,165 13,083 Other 2,315 1,935 Total accounts receivable 29,761 46,798 Less: allowance for doubtful accounts (1,117) (1,295) Total accounts receivable, net $ 28,644 $ 45,503 |
Balance and Activity in Allowance for Doubtful Accounts | The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Beginning balance $ 1,295 $ 1,274 $ 880 Additions charged to costs and expenses 6 758 397 Deductions(1) (184) (737) (3) Ending balance $ 1,117 $ 1,295 $ 1,274 ____________________ |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments, Gain (Loss) | The following table summarizes derivative activity for the years ended December 31, 2019, 2018 and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 (Gain) loss on commodity derivative contracts $ (1,094) $ 17,155 $ (24,090) Cash (received) paid on settlements $ (6,266) $ 35,325 $ (7,260) |
Offsetting Assets and Liabilities | The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2019 and 2018 (in thousands): December 31, 2019 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 114 $ — $ 114 $ — $ 114 Total $ 114 $ — $ 114 $ — $ 114 December 31, 2018 Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount Assets Derivative contracts - current $ 5,286 $ — $ 5,286 $ — $ 5,286 Total $ 5,286 $ — $ 5,286 $ — $ 5,286 |
Open Oil and Natural Gas Commodity Derivative Contracts | At December 31, 2019, the Company’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional (Bbl) Weighted Average Fixed Price January 2020 - March 2020 273,000 $ 61.05 |
Fair Value of Derivative Contracts | The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands): December 31, December 31, Type of Contract Balance Sheet Classification 2019 2018 Derivative assets Oil price swaps Derivative contracts - current $ 114 $ — Natural gas price swaps Derivative contracts - current $ — $ 5,286 Total net derivative contracts $ 114 $ 5,286 |
Leases (Table)
Leases (Table) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Lease, Cost | The components of lease costs recognized for the Company's ROU leases are shown below (in thousands): Year Ended December 31, 2019 Short-term lease cost (1) $ 9,994 Financing lease cost 1,397 Operating lease cost 188 Total lease cost $ 11,579 ___________________ (1) $4.8 million of short-term lease cost was capitalized as part of oil and natural gas properties during the year ended December 31, 2019. Portions of these costs were reimbursed to the Company by other working interest owners. |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment consists of the following (in thousands): December 31, 2019 2018 Oil and natural gas properties Proved $ 1,484,359 $ 1,269,091 Unproved 24,603 60,152 Total oil and natural gas properties 1,508,962 1,329,243 Less accumulated depreciation, depletion and impairment (1,129,622) (580,132) Net oil and natural gas properties capitalized costs 379,340 749,111 Land 4,400 4,400 Electrical infrastructure 126,482 131,176 Non-oil and natural gas equipment 12,665 13,458 Buildings and structures 77,148 77,148 Financing Leases 2,109 — Total 222,804 226,182 Less accumulated depreciation and amortization (34,201) (25,344) Other property, plant and equipment, net 188,603 200,838 Total property, plant and equipment, net $ 567,943 $ 949,949 |
Capitalized Costs of Unproved Properties Excluded from Amortization | The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2019 (in thousands): Year Cost Incurred Total 2019 2018 2017 2016 and Prior Property acquisition $ 23,973 $ 2,653 $ 2,353 $ 4,280 $ 14,687 Exploration 630 10 16 564 40 Total costs incurred $ 24,603 $ 2,663 $ 2,369 $ 4,844 $ 14,727 |
Impairment (Tables)
Impairment (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Impairment by Asset Class | Impairment The Company assesses the need to impair its oil and gas properties during its quarterly full cost pool ceiling limitation calculation. The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. The full cost pool ceiling limitation and estimated fair values of drilling, midstream, and other assets were determined in accordance with the policies discussed in Note 1. Impairment for the years ended December 31, 2019, 2018 and 2017 consists of the following (in thousands): Year Ended December 31, 2019 2018 2017 Full cost pool ceiling limitation(1) $ 409,574 $ — $ — Drilling assets(2) — 22 4,019 Midstream assets(3) — 4,148 — $ 409,574 $ 4,170 $ 4,019 ____________________ (1) Impairment recorded in the year ended December 31, 2019 largely resulted from a decrease in the trailing twelve-month weighted average SEC prices for oil and natural gas prices in 2019, lower NGL prices, increases in expected operating expenses, and other less significant inputs. See Note 22 for additional discussion of our oil and gas producing properties. (2) Impairment recorded in the years ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Expenses (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses consist of the following (in thousands): December 31, 2019 2018 Accounts payable and other accrued expenses $ 29,423 $ 62,733 Production payable 22,530 28,253 Payroll and benefits 7,021 12,891 Taxes payable 4,988 5,350 Drilling advances 514 2,031 Accrued interest 461 539 Total accounts payable and accrued expenses $ 64,937 $ 111,797 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-term debt consists of the following (in thousands): December 31, 2019 2018 Credit facility $ 57,500 $ — Total debt 57,500 — Less: current maturities of long-term debt — — Long-term debt $ 57,500 $ — |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations | The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands): Year Ended December 31, 2019 2018 2017 Beginning balance $ 60,064 $ 77,544 $ 106,481 Liability incurred upon acquiring and drilling wells 2,771 7,079 1,336 Revisions in estimated cash flows(1) 12,208 870 (28,565) Liability settled or disposed in current period(2) (5,379) (31,967) (11,308) Accretion 5,352 6,538 9,600 Ending balance 75,016 60,064 77,544 Less: current portion 22,119 25,393 41,017 Asset retirement obligations, net of current $ 52,897 $ 34,671 $ 36,527 ____________________ (1) Revisions for the years ended December 31, 2019, 2018 and 2017 relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
(Benefit) Provision for Income Taxes | The Company’s income tax (benefit) provision consisted of the following components (in thousands): Year Ended December 31, 2019 2018 2017 Current Federal $ — $ (33) $ (8,719) State — (38) (30) — (71) (8,749) Deferred Federal — — — State — — — — — — Total (benefit) provision $ — $ (71) $ (8,749) |
Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate | A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Computed at federal statutory rate $ (94,354) $ (1,921) $ 13,409 State taxes, net of federal benefit (20,500) 119 (284) Non-deductible expenses 137 849 1,711 Stock-based compensation 602 1,874 1,109 Discharge of debt and other reorganization related items — 206 1,018 Return to provision adjustments (1) (6,096) (1,292) 341,681 Impact of legislative changes — — 243,801 Release of valuation allowance — — (8,719) Change in valuation allowance 120,211 132 (602,452) Other — (38) (23) Total (benefit) provision $ — $ (71) $ (8,749) |
Deferred Tax Assets and Liabilities | Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands): December 31, 2019 December 31, 2018 Deferred tax liabilities Investments(1) $ 109,289 $ 112,343 Derivative contracts 29 1,128 Total deferred tax liabilities 109,318 113,471 Deferred tax assets Property, plant and equipment 300,704 267,865 Net operating loss carryforwards 383,418 302,190 Tax credits and other carryforwards 34,148 35,640 Asset retirement obligations 18,747 15,016 Other 2,290 3,816 Total deferred tax assets 739,307 624,527 Valuation allowance (629,989) (511,056) Net deferred tax liability $ — $ — ____________________ |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Equity [Abstract] | |
Treasury Stock Activity | The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired. Year Ended December 31, 2019 2018 2017 Number of shares withheld for taxes 56 495 349 Value of shares withheld for taxes $ 367 $ 7,420 $ 6,730 |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table disaggregates the Company’s revenue by source for the years ended December 31, 2019, 2018, and 2017 (in thousands): Year Ended December 31, 2019 2018 2017 Oil $ 186,360 $ 214,651 $ 202,539 NGL 35,598 67,111 61,322 Natural gas 44,146 66,964 92,349 Other 741 669 1,089 Total revenues $ 266,845 $ 349,395 $ 357,299 |
Share Based Compensation (Table
Share Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Summary of Unvested Restricted Stock Awards | The following table presents a summary of the Company’s unvested restricted stock awards: Number of Shares Weighted- Average Grant Date Fair Value (In thousands) Unvested restricted shares outstanding at December 31, 2016 1,407 $ 24.32 Granted 671 $ 19.97 Vested (827) $ 23.23 Forfeited / Canceled (146) $ 23.52 Unvested restricted shares outstanding at December 31, 2017 1,105 $ 22.62 Granted 370 $ 16.00 Vested (1,066) $ 22.63 Forfeited / Canceled (44) $ 21.04 Unvested restricted shares outstanding at December 31, 2018 365 $ 16.07 Granted 93 $ 8.06 Vested (1) (210) $ 16.29 Forfeited / Canceled (15) $ 16.25 Unvested restricted shares outstanding at December 31, 2019 233 $ 12.66 ____________________ (1) The aggregate intrinsic value of restricted stock that vested during 2019 was approximately $1.5 million based on the stock price at the time of vesting. Number of Fair Value per Unit at December 31, 2019 (In thousands) Unvested performance share units outstanding at December 31, 2016 — Granted 199 Vested — Forfeited / Canceled (16) Unvested performance share units outstanding at December 31, 2017 183 Granted 111 Vested (177) Forfeited / Canceled (6) Unvested performance share units outstanding at December 31, 2018 111 Granted — Vested (19) Forfeited / Canceled — Unvested performance share units outstanding at December 31, 2019 92 $ 20.41 |
Incentive-Based Compensation, Performance-based Units, Activity During Period | The following table presents a summary of the Company's performance units: Number of Fair Value per Unit at December 31, 2018 (In thousands) Unvested performance units outstanding at December 31, 2016 87 Granted — Vested (32) Forfeited / Canceled (6) Unvested performance units outstanding at December 31, 2017 49 Granted — Vested (48) Forfeited / Canceled (1) Unvested performance units outstanding at December 31, 2018 — $ — |
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan | The following tables summarize the Company's share and incentive-based compensation for the years ended December 31, 2019, 2018, and 2017 (in thousands): Recurring Compensation Expense(1) Executive Terminations(2) Reduction in Force(2) Accelerated Vesting(3) Total Year Ended December 31, 2019 Equity-classified awards: Restricted stock awards $ 2,526 $ 197 $ 500 $ — $ 3,223 Performance share units 282 281 — — 563 Stock options 661 12 — — 673 Total share-based compensation expense 3,469 490 500 — 4,459 Less: Capitalized compensation expense (204) — — — (204) Share and incentive-based compensation expense, net $ 3,265 $ 490 $ 500 $ — $ 4,255 Year Ended December 31, 2018 Equity-classified awards: Restricted stock awards $ 4,735 $ 8,140 $ 3,777 $ 5,181 $ 21,833 Performance share units 619 1,056 158 610 2,443 Total share-based compensation expense 5,354 9,196 3,935 5,791 24,276 Liability-classified awards: Performance units 756 2,151 558 1,309 4,774 Total share and incentive-based compensation expense 6,110 11,347 4,493 7,100 29,050 Less: Capitalized compensation expense (482) — — (555) (1,037) Share and incentive-based compensation expense, net $ 5,628 $ 11,347 $ 4,493 $ 6,545 $ 28,013 Year Ended December 31, 2017 Equity-classified awards: Restricted stock awards $ 14,731 $ 1,825 $ — $ — $ 16,556 Performance share units 1,356 — — — 1,356 Total share-based compensation expense 16,087 1,825 — — 17,912 Liability-classified awards: Performance units 2,574 — — — 2,574 Total share and incentive-based compensation expense 18,661 1,825 — — 20,486 Less: Capitalized compensation expense (2,521) — — — (2,521) Share and incentive-based compensation expense, net $ 16,140 $ 1,825 $ — $ — $ 17,965 ____________________ (1) Recorded in general and administrative expense in the accompanying consolidated statements of operations. (2) Recorded in employee termination benefits in the accompanying consolidated statements of operations. (3) Recorded in accelerated vesting of employment compensation in the accompanying consolidated statements of operations. |
Employee Termination Benefits (
Employee Termination Benefits (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Postemployment Benefits [Abstract] | |
Schedule of Postemployment Benefits | The following table presents a summary of employee termination benefits for the years ended December 31, 2019, 2018, and 2017 (in thousands): Cash Share-Based Compensation (6) Number of Shares Total Employee Termination Benefits Year Ended December 31, 2019 Executive Employee Termination Benefits(1) $ 1,194 $ 490 37 $ 1,684 Other Employee Termination Benefits(2) 2,608 500 44 3,108 $ 3,802 $ 990 81 $ 4,792 Year Ended December 31, 2018 Executive Employee Termination Benefits(3) $ 11,945 $ 9,196 554 $ 21,141 Other Employee Termination Benefits(4) 7,581 3,935 209 11,516 $ 19,526 $ 13,131 763 $ 32,657 Year Ended December 31, 2017 Executive Employee Termination Benefits(5) $ 2,500 $ 1,825 96 $ 4,325 Other Employee Termination Benefits 490 — — 490 $ 2,990 $ 1,825 96 $ 4,815 ____________________ (1) On December 12, 2019, the Company's then current CEO, Paul McKinney, separated employment from the Company, and on June 14, 2019, the Company’s then current Executive Vice President, General Counsel and Corporate Secretary, Philip Warman, separated employment from the Company. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2019. (2) As a result of a reduction in workforce in the second quarter of 2019, certain employees received termination benefits including cash severance and accelerated share-based compensation upon separation of service from the Company. (3) On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018. (4) As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company. (5) Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert. (6) Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reductions in workforce in 2019 and 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit. |
(Loss) Earnings per Share (Tabl
(Loss) Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |
Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share | The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share: Net (Loss) Income Weighted Average Shares (Loss) Earnings Per Share (In thousands, except per share amounts) Year Ended December 31, 2019 Basic loss per share $ (449,305) 35,427 $ (12.68) Effect of dilutive securities Restricted stock awards(1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (449,305) 35,427 $ (12.68) Year Ended December 31, 2018 Basic loss per share $ (9,075) 35,057 $ (0.26) Effect of dilutive securities Restricted stock awards(1) — — Performance share units(1) — — Warrants(1) — — Diluted loss per share $ (9,075) 35,057 $ (0.26) Year Ended December 31, 2017 Basic earnings per share $ 47,062 32,442 $ 1.45 Effect of dilutive securities Restricted stock awards — 221 Performance share units(2) — — Warrants(2) — — Diluted earnings per share $ 47,062 32,663 $ 1.44 ____________________ (1) No incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2019 and 2018, as their effect was antidilutive under the treasury stock method. (2) No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method. |
Supplemental Information on O_2
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Extractive Industries [Abstract] | |
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities | The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands): December 31, 2019 2018 2017 Oil and natural gas properties Proved $ 1,484,359 $ 1,269,091 $ 1,056,806 Unproved 24,603 60,152 100,884 Total oil and natural gas properties 1,508,962 1,329,243 1,157,690 Less accumulated depreciation, depletion and impairment (1,129,622) (580,132) (460,431) Net oil and natural gas properties capitalized costs $ 379,340 $ 749,111 $ 697,259 |
Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development | Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands): Year Ended December 31, 2019 2018 2017 Acquisitions of properties Proved $ (210) $ 30,641 $ 7,092 Unproved 2,653 4,197 91,139 Exploration 2,900 1,940 8,850 Development 156,210 158,361 187,264 Total cost incurred $ 161,553 $ 195,139 $ 294,345 |
Results of Operations for Oil, Natural Gas and NGL Producing Activities | The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings. Year Ended December 31, 2019 2018 2017 Revenues $ 266,104 $ 348,726 $ 356,210 Expenses Production costs 110,711 112,173 116,372 Depreciation and depletion 146,874 127,281 118,035 Impairment 409,574 — — Total expenses 667,159 239,454 234,407 Income (loss) before income taxes (401,055) 109,272 121,803 Income tax (benefit) expense (1) (105,477) 28,520 47,722 Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) $ (295,578) $ 80,752 $ 74,081 ____________________ (1) Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits. |
Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves | The summary below presents changes in the Company’s estimated reserves. Oil NGL Natural Gas Total (MBbls) (MBbls) (MMcf)(1) MBoe Proved developed and undeveloped reserves As of December 31, 2016 52,884 33,607 464,782 163,955 Revisions of previous estimates 804 2,628 44,679 10,879 Acquisitions of new reserves 18 70 683 202 Extensions and discoveries 12,446 1,914 30,080 19,373 Sales of reserves in place (204) (529) (7,055) (1,909) Production (4,157) (3,376) (44,237) (14,906) As of December 31, 2017 61,791 34,314 488,932 177,594 Revisions of previous estimates (2,316) (8,952) (131,518) (33,188) Acquisitions of new reserves 2,146 4,131 54,436 15,350 Extensions and discoveries 11,148 2,320 35,185 19,332 Sales of reserves in place (5,273) (809) (2,969) (6,577) Production (3,477) (2,829) (36,175) (12,335) As of December 31, 2018 64,019 28,175 407,891 160,176 Revisions of previous estimates (25,530) (9,277) (142,239) (58,514) Extensions and discoveries 635 94 2,127 1,084 Sales of reserves in place (297) (223) (2,308) (905) Production (3,519) (2,910) (33,164) (11,956) As of December 31, 2019 35,308 15,859 232,307 89,885 Proved developed reserves As of December 31, 2017 25,845 29,922 407,988 123,765 As of December 31, 2018 18,693 22,302 307,845 92,303 As of December 31, 2019 14,078 14,532 200,853 62,086 Proved undeveloped reserves As of December 31, 2017 35,946 4,392 80,944 53,829 As of December 31, 2018 45,326 5,873 100,046 67,873 As of December 31, 2019 21,230 1,327 31,454 27,799 _________________ (1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. |
Calculation of Weighted Average Per Unit Prices | The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: At December 31, 2019 2018 2017 Oil (per Bbl) $ 50.63 $ 60.86 $ 48.47 NGL (per Bbl) $ 12.45 $ 25.62 $ 20.28 Natural gas (per Mcf) $ 1.16 $ 1.77 $ 1.90 |
Standardized Measure of Discounted Future Cash Flows | The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands). December 31, 2019 2018 2017 Future cash inflows from production $ 2,254,530 $ 5,339,265 $ 4,621,615 Future production costs (1,028,695) (1,996,689) (1,837,852) Future development costs(1) (536,081) (1,170,113) (966,203) Future income tax expenses (2) — — (107) Undiscounted future net cash flows 689,754 2,172,463 1,817,453 10% annual discount (325,464) (1,126,860) (1,068,159) Standardized measure of discounted future net cash flows $ 364,290 $ 1,045,603 $ 749,294 ____________________ (1) Includes abandonment costs. (2) The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards. |
Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves | The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands): Year Ended December 31, 2019 2018 2017 Beginning present value $ 1,045,603 $ 749,294 $ 438,364 Changes during the year Revenues less production (155,772) (236,553) (239,838) Net changes in prices, production and other costs (491,035) 316,095 347,458 Development costs incurred 90,591 80,050 35,517 Net changes in future development costs(1) 450,162 (11,483) (64,484) Extensions and discoveries 11,921 102,961 112,556 Revisions of previous quantity estimates(1) (478,238) (91,038) 26,697 Accretion of discount 101,778 70,576 37,226 Net change in income taxes — 56 23 Purchases of reserves in-place — 35,713 454 Sales of reserves in-place (3,331) (2,029) (2,977) Timing differences and other(2) (207,389) 31,961 58,298 Net change for the year (681,313) 296,309 310,930 Ending present value(3) $ 364,290 $ 1,045,603 $ 749,294 ____________________ (1) The change in estimated future development costs and revisions of previous quantity estimates primarily reflect a decrease in planned PUD development due to declining year end SEC prices for oil and natural gas. (2) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. (3) Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices. |
Quarterly Financial Results (_2
Quarterly Financial Results (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Results (Unaudited) | The Company’s operating results for each quarter of 2019 and 2018 are summarized below (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter 2019 Total revenues $ 73,236 $ 75,388 $ 58,369 $ 59,852 Loss from operations(1)(2)(3) $ (4,261) $ (12,556) $ (181,707) $ (248,243) Net loss(1)(2)(3) $ (5,277) $ (13,284) $ (181,602) $ (249,142) Loss applicable per share to SandRidge Energy, Inc. common stockholders Basic $ (0.15) $ (0.38) $ (5.12) $ (7.01) Diluted $ (0.15) $ (0.38) $ (5.12) $ (7.01) ____________________ (1) Includes loss (gain) on derivative contracts of $0.2 million, $(1.8) million and $0.5 million for the first, third, and fourth quarters, respectively. (2) Includes employee termination benefits of $4.5 million and $0.3 million for the second quarter and fourth quarters, respectively. (3) Includes full cost ceiling limitation impairments of $165.5 million and $244.1 million for the third and fourth quarters, respectively. First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenues $ 87,128 $ 79,462 $ 97,660 $ 85,145 (Loss) income from operations(1)(2) $ (41,967) $ (33,685) $ 12,430 $ 52,847 Net (loss) income(1)(2) $ (40,894) $ (34,074) $ 11,715 $ 54,178 (Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders Basic $ (1.18) $ (0.97) $ 0.33 $ 1.53 Diluted $ (1.18) $ (0.97) $ 0.33 $ 1.53 ____________________ (1) Includes loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively. (2) Includes employee termination benefits of $31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Significant Accounting Policies [Line Items] | |||
Capitalized costs | $ 161,553,000 | $ 195,139,000 | $ 294,345,000 |
Maximum reserves sold from cost center not expected to result in significant alteration (less than) | 25.00% | ||
Interest capitalized during period | $ 1,500,000 | 0 | 0 |
Natural gas balancing liability | 1,600,000 | 1,700,000 | |
Internal Costs | |||
Significant Accounting Policies [Line Items] | |||
Capitalized costs | $ 5,700,000 | $ 8,800,000 | $ 14,800,000 |
Minimum | Buildings and structures | |||
Significant Accounting Policies [Line Items] | |||
Property, plant and equipment, useful life | 7 years | ||
Minimum | Equipment | |||
Significant Accounting Policies [Line Items] | |||
Property, plant and equipment, useful life | 1 year | ||
Maximum | Buildings and structures | |||
Significant Accounting Policies [Line Items] | |||
Property, plant and equipment, useful life | 39 years | ||
Maximum | Equipment | |||
Significant Accounting Policies [Line Items] | |||
Property, plant and equipment, useful life | 27 years |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Concentration Risk (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 | |
Concentration Risk [Line Items] | |||||||||||
Sales | $ 59,852 | $ 58,369 | $ 75,388 | $ 73,236 | $ 85,145 | $ 97,660 | $ 79,462 | $ 87,128 | |||
Targa Pipeline Mid-Continent West OK LLC | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Sales | $ 85,780 | $ 126,548 | $ 144,583 | ||||||||
Percentage of revenue | 32.10% | 36.20% | 40.50% | ||||||||
Sinclair Crude Company | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Sales | $ 74,810 | $ 62,623 | |||||||||
Percentage of revenue | 28.00% | 17.90% | |||||||||
Plains Marketing L.P. | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Sales | $ 69,214 | $ 102,182 | $ 117,927 | ||||||||
Percentage of revenue | 25.90% | 29.20% | 33.00% |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Disclosure of Cash Flow Information | |||
Cash paid for interest, net of amounts capitalized | $ (2,157) | $ (4,045) | $ (2,438) |
Cash received for income taxes | 0 | 4,381 | 4,348 |
Supplemental Disclosure of Noncash Investing and Financing Activities | |||
Purchase of PP&E in accounts payable | 4,592 | 34,235 | 50,096 |
Right-of-use assets obtained in exchange for financing lease obligations | 3,347 | ||
Carrying value of properties exchanged | 5,384 | 0 | 0 |
Equity issued for debt | $ 0 | $ 0 | $ (268,779) |
Acquisitions and Divestitures_2
Acquisitions and Divestitures of Oil and Gas Properties - Divestitures (Details) | Nov. 01, 2018USD ($)wellshares | Sep. 30, 2019USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
ARO liabilities settled or disposed | $ 5,400,000 | $ 5,379,000 | $ 31,967,000 | $ 11,308,000 | |
Gain (loss) recognized on transfer | $ 0 | ||||
Disposal Group, Not Discontinued Operations | Central Basin Platform | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
ARO liabilities settled or disposed | $ 26,900,000 | $ 26,900,000 | |||
Number of common units sold (in shares) | shares | 13,125,000 | ||||
Percent of common equity sold | 25.00% | ||||
Proceeds from sale of oil and natural gas properties | $ 14,500,000 | ||||
Number of wells sold | well | 1,066 | ||||
Disposal Group, Not Discontinued Operations | Oil and Gas Properties | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Proceeds from sale of oil and natural gas properties | $ 17,100,000 |
Acquisitions and Divestitures_3
Acquisitions and Divestitures of Oil and Gas Properties - Acquisitions (Details) $ in Thousands | Nov. 02, 2018USD ($)awell | Feb. 10, 2017USD ($)awell | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Acquisitions And Dispositions [Abstract] | |||||
Cash paid for acres | $ | $ 22,500 | $ 47,800 | |||
Liability incurred upon acquiring and drilling wells | $ | $ 6,400 | $ 2,771 | $ 7,079 | $ 1,336 | |
Number of wells acquired | well | 1,199 | 4 | |||
Percent of wells operated by company | 80.00% | ||||
Percent of working interest in acquired acres | 11.10% | ||||
Number of gross acres acquired | 397,000 | ||||
Number of net acres acquired | 44,000 | ||||
Percent of working interest in saltwater gathering and disposal system | 13.20% | ||||
Number of acres acquired | 13,000 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | $ 114 | $ 5,286 |
Recurring Measurement Basis | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Total Assets | 114 | 5,286 |
Netting, assets | 0 | 0 |
Recurring Measurement Basis | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Netting, assets | 0 | 0 |
Assets at Fair Value | 114 | 5,286 |
Recurring Measurement Basis | Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Total Assets | 0 | 0 |
Recurring Measurement Basis | Level 1 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | 0 | 0 |
Recurring Measurement Basis | Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Total Assets | 114 | 5,286 |
Recurring Measurement Basis | Level 2 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | 114 | 5,286 |
Recurring Measurement Basis | Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Total Assets | 0 | 0 |
Recurring Measurement Basis | Level 3 | Commodity derivative contracts | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items] | ||
Commodity derivative contracts | $ 0 | $ 0 |
Accounts Receivable - Summary o
Accounts Receivable - Summary of Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Receivables [Abstract] | ||||
Oil, natural gas and NGL sales | $ 22,281 | $ 31,780 | ||
Joint interest billing | 5,165 | 13,083 | ||
Other | 2,315 | 1,935 | ||
Total accounts receivable | 29,761 | 46,798 | ||
Less: allowance for doubtful accounts | (1,117) | (1,295) | $ (1,274) | $ (880) |
Total accounts receivable, net | $ 28,644 | $ 45,503 |
Accounts Receivable - Balance a
Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Receivables [Abstract] | |||
Beginning balance | $ 1,295 | $ 1,274 | $ 880 |
Additions charged to costs and expenses | 6 | 758 | 397 |
Deductions | (184) | (737) | (3) |
Ending balance | $ 1,117 | $ 1,295 | $ 1,274 |
Derivatives - Summary of Deriva
Derivatives - Summary of Derivative Activity (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2019USD ($)institution | Sep. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2019USD ($)institution | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||
(Gain) loss on derivative contracts | $ 500 | $ (1,800) | $ 200 | $ (42,600) | $ 11,300 | $ 30,100 | $ 18,300 | $ (1,094) | $ 17,155 | $ (24,090) |
Payments for (proceeds from) settlement of derivative contracts | $ (6,266) | 35,325 | (7,260) | |||||||
Number of counterparties to open derivative contracts | institution | 3 | 3 | ||||||||
Commodity Derivatives | ||||||||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||||||||
(Gain) loss on derivative contracts | $ (1,094) | 17,155 | (24,090) | |||||||
Payments for (proceeds from) settlement of derivative contracts | $ (6,266) | $ 35,325 | $ (7,260) |
Derivatives - Offsetting Assets
Derivatives - Offsetting Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
ASSETS | ||
Gross Amounts | $ 114 | $ 5,286 |
Gross Amounts Offset | 0 | 0 |
Amounts Net of Offset | 114 | 5,286 |
Financial Collateral | 0 | 0 |
Net Amount | 114 | 5,286 |
Derivative contracts - current | ||
ASSETS | ||
Gross Amounts | 114 | 5,286 |
Gross Amounts Offset | 0 | 0 |
Amounts Net of Offset | 114 | 5,286 |
Financial Collateral | 0 | 0 |
Net Amount | $ 114 | $ 5,286 |
Derivatives - Open Commodity De
Derivatives - Open Commodity Derivative Contracts (Details) - Oil Price Swaps, January 2018 - December 2018 | 12 Months Ended |
Dec. 31, 2019$ / bblMBbls | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Notional (Bbl) | MBbls | 273,000 |
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / bbl | 61.05 |
Derivatives - Fair Value of Der
Derivatives - Fair Value of Derivative Contracts (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Derivatives, Fair Value | ||
Derivative assets | $ 114 | $ 5,286 |
Total net derivative contracts | 114 | 5,286 |
Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative assets | 114 | 5,286 |
Oil price swaps | Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative assets | 114 | 0 |
Natural gas price swaps | Derivative contracts - current | ||
Derivatives, Fair Value | ||
Derivative assets | $ 0 | $ 5,286 |
Leases (Details)
Leases (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Jan. 01, 2019 | |
Lessee, Lease, Description [Line Items] | ||
Short-term lease cost | $ 9,994 | |
Financing lease cost | 1,397 | |
Operating lease cost | 188 | |
Total lease cost | 11,579 | |
Short-term lease, cost, capitalized | $ 4,800 | |
Accounting Standards Update 2016-02 [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Finance lease, right-of-use asset | $ 2,300 | |
Finance lease, liability | $ 2,400 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and natural gas properties, using full cost method of accounting | |||
Proved | $ 1,484,359 | $ 1,269,091 | $ 1,056,806 |
Unproved | 24,603 | 60,152 | 100,884 |
Total oil and natural gas properties | 1,508,962 | 1,329,243 | 1,157,690 |
Less: accumulated depreciation, depletion and impairment | (1,129,622) | (580,132) | (460,431) |
Net oil and natural gas properties capitalized costs | 379,340 | 749,111 | $ 697,259 |
Property, Plant and Equipment, Net | |||
Total | 226,182 | ||
Financing Leases | 2,109 | ||
Total | 222,804 | ||
Less accumulated depreciation and amortization | (34,201) | ||
Less accumulated depreciation and amortization | (25,344) | ||
Other property, plant and equipment, net | 188,603 | ||
Other property, plant and equipment, net | 200,838 | ||
Total property, plant and equipment, net | 567,943 | 949,949 | |
Land | |||
Property, Plant and Equipment, Net | |||
Total | 4,400 | 4,400 | |
Electrical infrastructure | |||
Property, Plant and Equipment, Net | |||
Total | 126,482 | 131,176 | |
Non-oil and natural gas equipment | |||
Property, Plant and Equipment, Net | |||
Total | 12,665 | 13,458 | |
Buildings and structures | |||
Property, Plant and Equipment, Net | |||
Total | $ 77,148 | $ 77,148 |
Property, Plant and Equipment -
Property, Plant and Equipment - Narrative (Details) - $ / Boe | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | |||
Average depreciation and depletion rate (usd per Boe) | 12.28 | 10.32 | 7.92 |
Expected completion of evaluation activities on majority of unproved properties | 10 years | ||
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Expect completion of evaluation activities on majority of unproved properties, without existing production | 3 years | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Expect completion of evaluation activities on majority of unproved properties, without existing production | 5 years |
Property, Plant and Equipment_3
Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | ||||
Property acquisition, cumulative | $ 23,973 | |||
Property acquisition | 2,653 | $ 2,353 | $ 4,280 | $ 14,687 |
Exploration, cumulative | 630 | |||
Exploration | 10 | 16 | 564 | 40 |
Total costs incurred, cumulative | 24,603 | |||
Total costs incurred | $ 2,663 | $ 2,369 | $ 4,844 | $ 14,727 |
Impairment (Details)
Impairment (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | |||||
Full cost pool ceiling impairments | $ 409,574 | $ 0 | |||
Asset impairment charges | $ 244,100 | $ 165,500 | 409,574 | 4,170 | $ 4,019 |
Assets held-for-sale, current, other | 5,700 | ||||
NRV of assets held-for-sale | 1,600 | ||||
Drilling assets | |||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | |||||
Asset impairment charges | 0 | 22 | 4,019 | ||
Midstream assets | |||||
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items] | |||||
Asset impairment charges | $ 0 | $ 4,148 | $ 0 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Payables and Accruals [Abstract] | ||
Accounts payable and other accrued expenses | $ 29,423 | $ 62,733 |
Production payable | 22,530 | 28,253 |
Payroll and benefits | 7,021 | 12,891 |
Taxes payable | 4,988 | 5,350 |
Other Accrued Liabilities, Current | 514 | 2,031 |
Interest Payable, Current | 461 | 539 |
Total accounts payable and accrued expenses | $ 64,937 | $ 111,797 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||
Total debt | $ 57,500 | $ 0 |
Less: current maturities of long-term debt | 0 | 0 |
Long-term debt | 57,500 | 0 |
Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Total debt | $ 57,500 | $ 0 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) - USD ($) | Jun. 21, 2019 | Jun. 20, 2019 | Feb. 28, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Nov. 30, 2019 | Oct. 31, 2018 | Sep. 30, 2018 |
Debt Instrument [Line Items] | |||||||||
Face value of long-term debt | $ 57,500,000 | $ 0 | |||||||
Repayments of long-term debt | 153,596,000 | 46,304,000 | $ 0 | ||||||
Gain on extinguishment of debt | 0 | 1,151,000 | $ 0 | ||||||
Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Face value of long-term debt | 57,500,000 | 0 | |||||||
Credit Facility [Member] | Revolving Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Maximum borrowing capacity | $ 600,000,000 | $ 225,000,000 | |||||||
Line of credit facility, current borrowing capacity | $ 300,000,000 | $ 350,000,000 | $ 425,000,000 | ||||||
Face value of long-term debt | 57,500,000 | ||||||||
Letters of credit outstanding | $ 2,900,000 | ||||||||
Line of credit facility, unused capacity, commitment fee percentage | 0.50% | ||||||||
Interest rate during period | 4.70% | ||||||||
Minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination | 95.00% | 85.00% | |||||||
Ratio of indebtedness to assets | 3.50 | ||||||||
Minimum consolidated interest coverage ratio | 2.25 | ||||||||
Ratio of indebtedness to assets | 0.38 | ||||||||
Interest coverage ratio | 37.89 | ||||||||
Credit Facility [Member] | Revolving Credit Facility | Minimum | Base Rate | |||||||||
Debt Instrument [Line Items] | |||||||||
Basis spread on variable rate | 1.00% | 2.00% | |||||||
Credit Facility [Member] | Revolving Credit Facility | Minimum | LIBOR | |||||||||
Debt Instrument [Line Items] | |||||||||
Basis spread on variable rate | 2.00% | 3.00% | |||||||
Credit Facility [Member] | Revolving Credit Facility | Maximum | Base Rate | |||||||||
Debt Instrument [Line Items] | |||||||||
Basis spread on variable rate | 2.00% | 3.00% | |||||||
Credit Facility [Member] | Revolving Credit Facility | Maximum | LIBOR | |||||||||
Debt Instrument [Line Items] | |||||||||
Basis spread on variable rate | 3.00% | 4.00% | |||||||
New Building Note [Member] | Secured Notes | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayments of long-term debt | $ 36,300,000 | ||||||||
Repurchased face amount | 35,000,000 | ||||||||
Paid-in-kind interest | $ 1,300,000 | ||||||||
Gain on extinguishment of debt | $ 1,200,000 |
Asset Retirement Obligations -
Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) - USD ($) $ in Thousands | Nov. 02, 2018 | Nov. 01, 2018 | Sep. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Beginning balance | $ 60,064 | $ 77,544 | $ 106,481 | |||
Liability incurred upon acquiring and drilling wells | $ 6,400 | 2,771 | 7,079 | 1,336 | ||
Revisions in estimated cash flows | 12,208 | 870 | (28,565) | |||
Liability settled or disposed in current period | $ (5,400) | (5,379) | (31,967) | (11,308) | ||
Accretion | 5,352 | 6,538 | 9,600 | |||
Ending balance | 75,016 | 60,064 | 77,544 | |||
Less: current portion | 22,119 | 25,393 | 41,017 | |||
Asset retirement obligations, net of current | $ 52,897 | 34,671 | $ 36,527 | |||
Central Basin Platform | Disposal Group, Not Discontinued Operations | ||||||
Asset Retirement Obligation, Roll Forward Analysis | ||||||
Liability settled or disposed in current period | $ (26,900) | $ (26,900) |
Income Taxes - (Benefit) Provis
Income Taxes - (Benefit) Provision for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Current | |||
Federal | $ 0 | $ (33) | $ (8,719) |
State | 0 | (38) | (30) |
Current, total | 0 | (71) | (8,749) |
Deferred | |||
Federal | 0 | 0 | 0 |
State | 0 | 0 | 0 |
Deferred, total | 0 | 0 | 0 |
Total (benefit) provision | $ 0 | $ (71) | $ (8,749) |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of (Benefit) Provision for Income Taxes at Statutory Federal Tax Rate to Company's Actual Income Tax (Benefit) Provision (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Computed at federal statutory rate | $ (94,354) | $ (1,921) | $ 13,409 |
State taxes, net of federal benefit | (20,500) | 119 | (284) |
Non-deductible expenses | 137 | 849 | 1,711 |
Stock-based compensation | 602 | 1,874 | 1,109 |
Discharge of debt and other reorganization related items | 0 | 206 | 1,018 |
Return to provision adjustments | (6,096) | (1,292) | 341,681 |
Impact of legislative changes | 0 | 0 | 243,801 |
Release of valuation allowance | 0 | 0 | (8,719) |
Change in valuation allowance | 120,211 | 132 | (602,452) |
Other | 0 | (38) | (23) |
Total (benefit) provision | $ 0 | $ (71) | $ (8,749) |
Income Taxes - Deferred Tax Ass
Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax liabilities | ||
Investments | $ 109,289 | $ 112,343 |
Derivative contracts | 29 | 1,128 |
Total deferred tax liabilities | 109,318 | 113,471 |
Deferred tax assets | ||
Property, plant and equipment | 300,704 | 267,865 |
Net operating loss carryforwards | 383,418 | 302,190 |
Tax credits and other carryforwards | 34,148 | 35,640 |
Asset retirement obligations | 18,747 | 15,016 |
Other | 2,290 | 3,816 |
Total deferred tax assets | 739,307 | 624,527 |
Valuation allowance | (629,989) | (511,056) |
Net deferred tax liability | $ 0 | $ 0 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | |||
Income tax expense (benefit) | $ 0 | $ (71) | $ (8,749) |
Income tax expense due to TCJA | $ 243,800 | ||
Minimum | |||
Operating Loss Carryforwards [Line Items] | |||
Number of tax years open for state tax audit (in years) | 3 years | ||
Maximum | |||
Operating Loss Carryforwards [Line Items] | |||
Number of tax years open for state tax audit (in years) | 5 years | ||
Domestic Tax Authority | |||
Operating Loss Carryforwards [Line Items] | |||
Federal net operating loss carryovers | $ 1,400,000 | ||
Operating loss carryforwards, subject to expiration | 800,000 | ||
Operating loss carryforwards, not subject to expiration | 600,000 | ||
Tax credits, not subject to expiration | $ 32,000 |
Equity - Additional Information
Equity - Additional Information (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Class of Stock [Line Items] | ||
Common stock, issued (in shares) | 35,772,000 | 35,687,000 |
Common stock, outstanding (in shares) | 35,772,000 | 35,687,000 |
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Nonvested (in shares) | 200,000 | |
Shares authorized (in shares) | 250,000,000 | 250,000,000 |
Number of securities issued for each warrant (in shares) | 1 | |
Series A Warrants | ||
Class of Stock [Line Items] | ||
Common stock issued for general unsecured claims (in shares) | 4,700,000 | |
Exercise price of warrants (in usd per share) | $ 41.34 | |
Series B Warrants | ||
Class of Stock [Line Items] | ||
Common stock issued for general unsecured claims (in shares) | 2,000,000 | |
Exercise price of warrants (in usd per share) | $ 42.03 |
Equity - Shares Withheld for Ta
Equity - Shares Withheld for Taxes (Details) - Treasury Stock [Member] - USD ($) shares in Thousands, $ 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] | |||
Number of shares withheld for taxes | 56 | 495 | 349 |
Value of shares withheld for taxes | $ 367 | $ 7,420 | $ 6,730 |
Revenues - Disaggregation of Re
Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | |||
Revenues | $ 266,845 | $ 349,395 | $ 357,299 |
Oil | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 186,360 | 214,651 | 202,539 |
NGL | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 35,598 | 67,111 | 61,322 |
Natural gas | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | 44,146 | 66,964 | 92,349 |
Other | |||
Disaggregation of Revenue [Line Items] | |||
Revenues | $ 741 | $ 669 | $ 1,089 |
Revenues - Additional Informati
Revenues - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Revenue Receivable from Contract with Customer | ||
Disaggregation of Revenue [Line Items] | ||
Accounts receivable, gross | $ 22.3 | $ 31.8 |
Share Based Compensation - Narr
Share Based Compensation - Narrative (Details) | 1 Months Ended | 12 Months Ended | ||
Oct. 31, 2016$ / Unit | Dec. 31, 2019 | Feb. 28, 2017shares | Oct. 04, 2016shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares authorized (in shares) | 4,600,000 | |||
Restricted Stock | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Period of recognition for unrecognized costs | 1 year 3 months 18 days | |||
Performance Shares | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance share plan, conversion to common stock (in shares) | 1 | |||
Performance Units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Weighted average grant date fair value | $ / Unit | 100 | |||
Minimum | Restricted Stock | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 1 year | |||
Maximum | Restricted Stock | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period (in years) | 3 years |
Share Based Compensation - Summ
Share Based Compensation - Summary of Unvested Restricted Stock Awards (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Number of Shares | ||||
Unvested shares/units outstanding at end of period (in shares) | 200,000 | |||
Restricted Stock | ||||
Number of Shares | ||||
Unvested shares/units outstanding at beginning of period (in shares) | 365,000 | 1,105,000 | 1,407,000 | |
Granted (in shares) | 93,000 | 370,000 | 671,000 | |
Vested (in shares) | (210,000) | (1,066,000) | (827,000) | |
Forfeited / Canceled (in shares) | (15,000) | (44,000) | (146,000) | |
Unvested shares/units outstanding at end of period (in shares) | 233,000 | 365,000 | 1,105,000 | |
Weighted- Average Grant Date Fair Value (usd per share) | ||||
Unvested shares/units outstanding (in usd per share) | $ 12.66 | $ 16.07 | $ 22.62 | $ 24.32 |
Granted (in usd per share) | 8.06 | 16 | 19.97 | |
Vested (in usd per share) | 16.29 | 22.63 | 23.23 | |
Forfeited / Canceled (in usd per share) | $ 16.25 | $ 21.04 | $ 23.52 | |
Aggregate intrinsic value of restricted stock vested during period | $ 1.5 | |||
Performance Shares | ||||
Number of Shares | ||||
Unvested shares/units outstanding at beginning of period (in shares) | 111,000 | 183,000 | 0 | |
Granted (in shares) | 0 | 111,000 | 199,000 | |
Vested (in shares) | (19,000) | (177,000) | 0 | |
Forfeited / Canceled (in shares) | 0 | (6,000) | (16,000) | |
Unvested shares/units outstanding at end of period (in shares) | 92,000 | 111,000 | 183,000 | |
Weighted- Average Grant Date Fair Value (usd per share) | ||||
Unvested shares/units outstanding (in usd per share) | $ 20.41 | |||
Performance Units | ||||
Number of Shares | ||||
Unvested shares/units outstanding at beginning of period (in shares) | 0 | 49,000 | 87,000 | |
Granted (in shares) | 0 | 0 | ||
Vested (in shares) | (48,000) | (32,000) | ||
Forfeited / Canceled (in shares) | (1,000) | (6,000) | ||
Unvested shares/units outstanding at end of period (in shares) | 0 | 49,000 | ||
Weighted- Average Grant Date Fair Value (usd per share) | ||||
Unvested shares/units outstanding (in usd per share) | $ 0 |
Share Based Compensation - Shar
Share Based Compensation - Share-based Compensation Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 4,459 | $ 24,276 | $ 17,912 |
Performance units | 4,774 | 2,574 | |
Total share and incentive-based compensation expense | 29,050 | 20,486 | |
Less: Capitalized compensation expense | (204) | (1,037) | (2,521) |
Share and incentive-based compensation expense, net | $ 4,255 | 28,013 | 17,965 |
Accelerated vesting, per unit (in shares) | 1 | ||
Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 3,469 | 5,354 | 16,087 |
Performance units | 756 | 2,574 | |
Total share and incentive-based compensation expense | 6,110 | 18,661 | |
Less: Capitalized compensation expense | (204) | (482) | (2,521) |
Share and incentive-based compensation expense, net | 3,265 | 5,628 | 16,140 |
Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 490 | 9,196 | 1,825 |
Performance units | 2,151 | 0 | |
Total share and incentive-based compensation expense | 11,347 | 1,825 | |
Less: Capitalized compensation expense | 0 | 0 | 0 |
Share and incentive-based compensation expense, net | 490 | 11,347 | 1,825 |
Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 500 | 3,935 | 0 |
Performance units | 558 | 0 | |
Total share and incentive-based compensation expense | 4,493 | 0 | |
Less: Capitalized compensation expense | 0 | 0 | 0 |
Share and incentive-based compensation expense, net | 500 | 4,493 | 0 |
Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 5,791 | 0 |
Performance units | 1,309 | 0 | |
Total share and incentive-based compensation expense | 7,100 | 0 | |
Less: Capitalized compensation expense | 0 | (555) | 0 |
Share and incentive-based compensation expense, net | 0 | 6,545 | 0 |
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 3,223 | 21,833 | 16,556 |
Restricted Stock | Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 2,526 | 4,735 | 14,731 |
Restricted Stock | Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 197 | 8,140 | 1,825 |
Restricted Stock | Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 500 | 3,777 | 0 |
Restricted Stock | Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 5,181 | 0 |
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 563 | 2,443 | 1,356 |
Performance Shares | Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 282 | 619 | 1,356 |
Performance Shares | Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 281 | 1,056 | 0 |
Performance Shares | Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | 158 | 0 |
Performance Shares | Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | $ 610 | $ 0 |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 673 | ||
Stock Options | Recurring Compensation Expense | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 661 | ||
Stock Options | Executive Terminations | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 12 | ||
Stock Options | Reduction in Force | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | 0 | ||
Stock Options | Accelerated Vesting | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Total share-based compensation expense | $ 0 |
Incentive and Deferred Compen_2
Incentive and Deferred Compensation Plans (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Annual Incentive Plan | ||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||
Accrued bonuses | $ 2.7 | |||
Payments to employees | $ 7.1 | |||
Minimum | Annual Incentive Plan | ||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||
Incentive plans, payout percentages of target values | 0.00% | |||
Maximum | Annual Incentive Plan | ||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||
Incentive plans, payout percentages of target values | 200.00% | |||
Other Postretirement Benefits Plan | ||||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | ||||
Retirement plan, employer matching contribution, percent of match | 100.00% | 100.00% | 100.00% | |
Retirement plan, employer matching contribution, percent of employees' gross pay (up to) | 10.00% | 10.00% | 10.00% | |
Retirement plan, cost recognized | $ 2.2 | $ 2.8 | $ 3.6 | |
Percent of employee contributions vesting immediately | 100.00% | 100.00% | 100.00% | |
Retirement plan, employer matching contribution, vesting period | 4 years | 4 years | 4 years |
Proxy Contest (Details)
Proxy Contest (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | ||||
Proxy contest | $ 7,200 | $ 0 | $ 7,139 | $ 0 |
Employee Termination Benefits_2
Employee Termination Benefits (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2019 | Jun. 30, 2019 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | $ 3,802 | $ 19,526 | $ 2,990 | |||
Share-Based Compensation | $ 990 | $ 13,131 | $ 1,825 | |||
Number of Shares (in shares) | 81 | 763 | 96 | |||
Total Employee Termination Benefits | $ 300 | $ 4,500 | $ 31,600 | $ 4,792 | $ 32,657 | $ 4,815 |
Executive Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 1,194 | 11,945 | 2,500 | |||
Share-Based Compensation | $ 490 | $ 9,196 | $ 1,825 | |||
Number of Shares (in shares) | 37 | 554 | 96 | |||
Total Employee Termination Benefits | $ 1,684 | $ 21,141 | $ 4,325 | |||
Other Employee Termination Benefits | ||||||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | ||||||
Cash | 2,608 | 7,581 | 490 | |||
Share-Based Compensation | $ 500 | $ 3,935 | $ 0 | |||
Number of Shares (in shares) | 44 | 209 | 0 | |||
Total Employee Termination Benefits | $ 3,108 | $ 11,516 | $ 490 |
(Loss) Earnings per Share - Cal
(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 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 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||
Net (Loss) Income | $ (449,305) | $ (9,075) | $ 47,062 | ||||||||
Weighted Average Shares, basic (in shares) | 35,427,000 | 35,057,000 | 32,442,000 | ||||||||
(Loss) Earnings Per Share, Basic (in dollars per share) | $ (7.01) | $ (5.12) | $ (0.38) | $ (0.15) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (12.68) | $ (0.26) | $ 1.45 |
Effect of dilutive securities | |||||||||||
Net (Loss) Income, Restricted stock | $ 0 | $ 0 | $ 0 | ||||||||
Weighted Average Shares, Restricted stock awards (in shares) | 0 | 0 | 221,000 | ||||||||
Net (Loss) Income, Performance share units | $ 0 | $ 0 | $ 0 | ||||||||
Weighted Average Shares, Performance share units (in shares) | 0 | 0 | 0 | ||||||||
Net (Loss) Income, Warrants | $ 0 | $ 0 | $ 0 | ||||||||
Weighted Average Shares, Warrants (in shares) | 0 | 0 | 0 | ||||||||
Net (Loss) Income, Diluted | $ (449,305) | $ (9,075) | $ 47,062 | ||||||||
Weighted Average Shares, Diluted (in shares) | 35,427,000 | 35,057,000 | 32,663,000 | ||||||||
(Loss) Earnings Per Share, Diluted (in dollars per share) | $ (7.01) | $ (5.12) | $ (0.38) | $ (0.15) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (12.68) | $ (0.26) | $ 1.44 |
Warrants | |||||||||||
Effect of dilutive securities | |||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | 0 | ||||||||
Performance Share Units | |||||||||||
Effect of dilutive securities | |||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | 0 | ||||||||
Restricted Stock | |||||||||||
Effect of dilutive securities | |||||||||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 |
Supplemental Information on O_3
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Oil and natural gas properties | |||
Proved | $ 1,484,359 | $ 1,269,091 | $ 1,056,806 |
Unproved | 24,603 | 60,152 | 100,884 |
Total oil and natural gas properties | 1,508,962 | 1,329,243 | 1,157,690 |
Less: accumulated depreciation, depletion and impairment | (1,129,622) | (580,132) | (460,431) |
Net oil and natural gas properties capitalized costs | $ 379,340 | $ 749,111 | $ 697,259 |
Supplemental Information on O_4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Acquisitions of properties | |||
Proved | $ (210) | $ 30,641 | $ 7,092 |
Unproved | 2,653 | 4,197 | 91,139 |
Exploration | 2,900 | 1,940 | 8,850 |
Development | 156,210 | 158,361 | 187,264 |
Total cost incurred | $ 161,553 | $ 195,139 | $ 294,345 |
Supplemental Information on O_5
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Results of Operations for Oil and Gas Producing Activities | |||
Revenues | $ 266,845 | $ 349,395 | $ 357,299 |
Expenses | |||
Production costs | 110,711 | 112,173 | 116,372 |
Depreciation and depletion | 146,874 | 127,281 | 118,035 |
Impairment | 409,574 | 0 | 0 |
Total expenses | 667,159 | 239,454 | 234,407 |
Income (loss) before income taxes | (401,055) | 109,272 | 121,803 |
Income tax expense (benefit) | (105,477) | 28,520 | 47,722 |
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) | (295,578) | 80,752 | 74,081 |
Oil, natural gas and NGL | |||
Results of Operations for Oil and Gas Producing Activities | |||
Revenues | $ 266,104 | $ 348,726 | $ 356,210 |
Supplemental Information on O_6
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details) Mcf in Thousands | 12 Months Ended | ||
Dec. 31, 2019MBoeMcfMBbls | Dec. 31, 2018MBoeMcfMBbls | Dec. 31, 2017MBoeMBblsMcf | |
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | |||
Proved developed and undeveloped reserves, Beginning balance (MBoe) | MBoe | 160,176 | 177,594 | 163,955 |
Revisions of previous estimates (MBoe) | MBoe | (58,514) | (33,188) | 10,879 |
Acquisitions of new reserves (MBoe) | MBoe | 15,350 | 202 | |
Extensions and discoveries (MBoe) | MBoe | 1,084 | 19,332 | 19,373 |
Sales of reserves in place (MBoe) | MBoe | (905) | (6,577) | (1,909) |
Production (MBoe) | MBoe | (11,956) | (12,335) | (14,906) |
Proved developed and undeveloped reserves, Ending balance (MBoe) | MBoe | 89,885 | 160,176 | 177,594 |
Proved developed reserves (MBoe) | MBoe | 62,086 | 92,303 | 123,765 |
Proved undeveloped reserves (MBoe) | MBoe | 27,799 | 67,873 | 53,829 |
Oil | |||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | |||
Proved developed and undeveloped reserves, beginning balance | 64,019 | 61,791 | 52,884 |
Revisions of previous estimates | (25,530) | (2,316) | 804 |
Acquisitions of new reserves | 2,146 | 18 | |
Extensions and discoveries | 635 | 11,148 | 12,446 |
Sales of reserves in place | (297) | (5,273) | (204) |
Production | (3,519) | (3,477) | (4,157) |
Proved developed and undeveloped reserves, ending balance | 35,308 | 64,019 | 61,791 |
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 14,078 | 18,693 | 25,845 |
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 21,230 | 45,326 | 35,946 |
NGL | |||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | |||
Proved developed and undeveloped reserves, beginning balance | 28,175 | 34,314 | 33,607 |
Revisions of previous estimates | (9,277) | (8,952) | 2,628 |
Acquisitions of new reserves | 4,131 | 70 | |
Extensions and discoveries | 94 | 2,320 | 1,914 |
Sales of reserves in place | (223) | (809) | (529) |
Production | (2,910) | (2,829) | (3,376) |
Proved developed and undeveloped reserves, ending balance | 15,859 | 28,175 | 34,314 |
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 14,532 | 22,302 | 29,922 |
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | 1,327 | 5,873 | 4,392 |
Natural gas | |||
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | |||
Proved developed and undeveloped reserves, beginning balance | Mcf | 407,891 | 488,932 | 464,782 |
Revisions of previous estimates | Mcf | (142,239) | (131,518) | 44,679 |
Acquisitions of new reserves | Mcf | 54,436 | 683 | |
Extensions and discoveries | Mcf | 2,127 | 35,185 | 30,080 |
Sales of reserves in place | Mcf | (2,308) | (2,969) | (7,055) |
Production | Mcf | (33,164) | (36,175) | (44,237) |
Proved developed and undeveloped reserves, ending balance | Mcf | 232,307 | 407,891 | 488,932 |
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 200,853 | 307,845 | 407,988 |
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf | 31,454 | 100,046 | 80,944 |
Supplemental Information on O_7
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Calculation of Weighted Average Per Unit Prices (Unaudited) (Details) | 12 Months Ended | ||
Dec. 31, 2019$ / bbl$ / Mcf | Dec. 31, 2018$ / Mcf$ / bbl | Dec. 31, 2017$ / bbl$ / Mcf | |
Oil | |||
Oil and Gas, Present Activity [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | 50.63 | 60.86 | 48.47 |
NGL | |||
Oil and Gas, Present Activity [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | 12.45 | 25.62 | 20.28 |
Natural gas | |||
Oil and Gas, Present Activity [Line Items] | |||
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf | 1.16 | 1.77 | 1.90 |
Supplemental Information on O_8
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details) | 12 Months Ended | |||
Dec. 31, 2019MBoe | Dec. 31, 2018MBoe | Dec. 31, 2017MBoe | Dec. 31, 2016MBoe | |
Extractive Industries [Abstract] | ||||
Percentage of proved reserves estimates prepared by external engineers | 0.90 | |||
Proved developed and undeveloped reserves (MBoe) | 89,885 | 160,176 | 177,594 | 163,955 |
Decrease due to change in accounting (MBoe) | 50,900 | |||
Decrease due to change in accounting, PUD | 39,800 | |||
Decrease due to change in accounting, Remaining Proved Reserves | 11,100 | |||
Revision of previous estimates due to changes in commodity pricing (MBoe) | 10,900 | |||
Revision of previous estimates due to changes in well performance (MBoe) | 3,200 | 8,300 | ||
Improved recovery (MBoe) | 12,600 | |||
Change in economic life | 24,900 | |||
Revision of previous estimates (MBoe) | (58,514) | (33,188) | 10,879 | |
Sales of reserves in place (MBoe) | 905 | 6,577 | 1,909 | |
Acquisitions of new reserves (MBoe) | 15,350 | 202 | ||
Upward revision of estimates due to extensions (MBoe) | 1,084 | 19,332 | 19,373 |
Supplemental Information on O_9
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Extractive Industries [Abstract] | ||||
Future cash inflows from production | $ 2,254,530 | $ 5,339,265 | $ 4,621,615 | |
Future production costs | (1,028,695) | (1,996,689) | (1,837,852) | |
Future development costs | (536,081) | (1,170,113) | (966,203) | |
Future income tax expenses | 0 | 0 | (107) | |
Undiscounted future net cash flows | 689,754 | 2,172,463 | 1,817,453 | |
10% annual discount | (325,464) | (1,126,860) | (1,068,159) | |
Standardized measure of discounted future net cash flows | $ 364,290 | $ 1,045,603 | $ 749,294 | $ 438,364 |
Supplemental Information on _10
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Beginning present value | $ 1,045,603 | $ 749,294 | $ 438,364 |
Changes during the year | |||
Revenues less production | (155,772) | (236,553) | (239,838) |
Net changes in prices, production and other costs | (491,035) | 316,095 | 347,458 |
Development costs incurred | 90,591 | 80,050 | 35,517 |
Net changes in future development costs | 450,162 | (11,483) | (64,484) |
Extensions and discoveries | 11,921 | 102,961 | 112,556 |
Revisions of previous quantity estimates | (478,238) | (91,038) | 26,697 |
Accretion of discount | 101,778 | 70,576 | 37,226 |
Net change in income taxes | 0 | 56 | 23 |
Purchases of reserves in-place | 0 | 35,713 | 454 |
Sales of reserves in-place | (3,331) | (2,029) | (2,977) |
Timing differences and other | (207,389) | 31,961 | 58,298 |
Net change for the year | (681,313) | 296,309 | 310,930 |
Ending present value | $ 364,290 | $ 1,045,603 | $ 749,294 |
Quarterly Financial Results (_3
Quarterly Financial Results (Unaudited) (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 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total revenues | $ 59,852 | $ 58,369 | $ 75,388 | $ 73,236 | $ 85,145 | $ 97,660 | $ 79,462 | $ 87,128 | |||
(Loss) income from operations | (248,243) | (181,707) | (12,556) | (4,261) | 52,847 | 12,430 | (33,685) | (41,967) | $ (446,767) | $ (10,375) | $ 39,631 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ (249,142) | $ (181,602) | $ (13,284) | $ (5,277) | $ 54,178 | $ 11,715 | $ (34,074) | $ (40,894) | $ (449,305) | $ (9,075) | $ 47,062 |
Loss applicable per share to SandRidge Energy, Inc. common stockholders | |||||||||||
Basic (in dollars per share) | $ (7.01) | $ (5.12) | $ (0.38) | $ (0.15) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (12.68) | $ (0.26) | $ 1.45 |
Diluted (in dollars per share) | $ (7.01) | $ (5.12) | $ (0.38) | $ (0.15) | $ 1.53 | $ 0.33 | $ (0.97) | $ (1.18) | $ (12.68) | $ (0.26) | $ 1.44 |
(Gain) loss on derivative contracts | $ 500 | $ (1,800) | $ 200 | $ (42,600) | $ 11,300 | $ 30,100 | $ 18,300 | $ (1,094) | $ 17,155 | $ (24,090) | |
Employee termination benefits | 300 | $ 4,500 | $ 31,600 | 4,792 | 32,657 | 4,815 | |||||
Impairment | $ 244,100 | $ 165,500 | 409,574 | 4,170 | 4,019 | ||||||
Accelerated vesting of employment compensation | 6,500 | 0 | 6,545 | 0 | |||||||
Proxy contest | $ 7,200 | $ 0 | $ 7,139 | $ 0 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event | Feb. 04, 2020employee |
Subsequent Event [Line Items] | |
Number of positions eliminated | 63 |
Number of positions before restructuring event | 120 |
Uncategorized Items - sd-201912
Label | Element | Value |
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ (57,000) |
Retained Earnings [Member] | ||
Cumulative Effect of New Accounting Principle in Period of Adoption | us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption | $ (57,000) |