Document and Entity Information
Document and Entity Information Document and Entity Information | 12 Months Ended |
Dec. 31, 2020 | |
Document And Entity Information [Abstract] | |
Document Type | 10-K |
Document Annual Report | true |
Document Period End Date | Dec. 31, 2020 |
Document Transition Report | false |
Entity File Number | 1-9260 |
Entity Registrant Name | UNIT CORPORATION |
Entity Incorporation, State or Country Code | DE |
Entity Tax Identification Number | 73-1283193 |
Entity Address, Address Line One | 8200 South Unit Drive, |
Entity Address, City or Town | Tulsa, |
Entity Address, State or Province | OK |
Entity Address, Country | US |
Entity Address, Postal Zip Code | 74132 |
City Area Code | (918) |
Local Phone Number | 493-7700 |
Title of 12(b) Security | N/A |
Trading Symbol | N/A |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | Yes |
Entity Current Reporting Status | No |
Entity Interactive Data Current | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | true |
Entity Emerging Growth Company | false |
Entity Shell Company | false |
Amendment Flag | false |
Document Fiscal Year Focus | 2020 |
Document Fiscal Period Focus | FY |
Entity Central Index Key | 0000798949 |
Current Fiscal Year End Date | --12-31 |
Entity Bankruptcy Proceedings, Reporting Current | true |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | |
Current assets: | |||
Cash and cash equivalents | $ 12,145 | $ 571 | |
Restricted Cash | 569 | 0 | |
Accounts receivable, net of allowance for doubtful accounts of $3,783 and $2,332 at December 31, 2020 and December 31, 2019, respectively | 57,846 | 82,656 | |
Materials and supplies | 0 | 449 | |
Current derivative asset (Note 15) | 0 | 633 | |
Current income taxes receivable | 1,150 | 1,756 | |
Assets held for sale (Note 4) | 0 | 5,908 | |
Prepaid expenses and other | 11,212 | 13,078 | |
Total current assets | 82,922 | 105,051 | |
Oil and natural gas properties, on the full cost method: | |||
Proved properties | 238,581 | 6,341,582 | |
Unproved properties not being amortized | 1,591 | 252,874 | |
Drilling equipment | 63,687 | 1,295,713 | |
Gas gathering and processing equipment | 251,404 | 824,699 | |
Saltwater disposal systems | 0 | 69,692 | |
Land and building | 32,635 | 59,080 | |
Transportation equipment | 3,130 | 29,723 | |
Other | 9,961 | 57,992 | |
Property, plant and equipment, gross, total | 600,989 | 8,931,355 | |
Less accumulated depreciation, depletion, amortization, and impairment | 54,189 | 6,978,669 | |
Net property and equipment | 546,800 | 1,952,686 | |
Right of use asset (Note 17) | 5,592 | 5,673 | |
Other assets | 14,389 | 26,642 | |
Total assets | [1] | 649,703 | 2,090,052 |
Current liabilities: | |||
Accounts payable | 40,829 | 84,481 | |
Accrued liabilities (Note 8) | 21,743 | 46,562 | |
Current operating lease liability (Note 17) | 4,075 | 3,430 | |
Current portion of long-term debt (Note 9) | 600 | 108,200 | |
Current derivative liabilities (Note 15) | 1,047 | 0 | |
Warrant liability (Note 2) | 885 | 0 | |
Current portion of other long-term liabilities (Note 9) | 11,168 | 17,376 | |
Total current liabilities | 80,347 | 260,049 | |
Long-term debt less debt issuance costs (Note 9) | 98,400 | 663,216 | |
Non-current derivative liabilities (Note 15) | 4,659 | 27 | |
Operating Lease, Liability, Noncurrent | 1,445 | 2,071 | |
Other long-term liabilities (Note 9) | 39,259 | 95,341 | |
Deferred income taxes (Note 11) | 0 | 13,713 | |
Commitments and contingencies (Note 18) | |||
Shareholders' equity: | |||
Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019 | 0 | 0 | |
Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at December 31, 2020 | 0 | 0 | |
Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019 | 120 | 10,591 | |
Successor common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued as of December 31, 2020 | 120 | 10,591 | |
Capital in excess of par value | 197,242 | 644,152 | |
Retained earnings (deficit) | (18,140) | 199,135 | |
Total shareholders' equity attributable to Unit Corporation | 179,222 | 853,878 | |
Non-controlling interests in consolidated subsidiaries | 246,371 | 201,757 | |
Total shareholders' equity | 425,593 | 1,055,635 | |
Total liabilities and shareholders' equity | [1] | $ 649,703 | $ 2,090,052 |
[1] | Unit Corporation's consolidated total assets as of December 31, 2020 include current and long-term assets of its variable interest entity (VIE) (Superior) of $45.8 million and $247.8 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 19 – Variable Interest Entity Arrangements. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Accounts receivable, allowance for doubtful accounts | $ 3,783 | $ 2,332 |
Preferred stock, par value | $ 0.01 | $ 1 |
Preferred stock, shares authorized | 1,000,000 | 5,000,000 |
Preferred stock, issued | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.20 |
Common stock, shares authorized | 25,000,000 | 175,000,000 |
Common stock, shares issued | 12,000,000 | 55,443,393 |
VIE Current assets pledged | $ 45,800 | $ 28,800 |
VIE Non-current assets pledged | 247,800 | 434,300 |
VIE Current liabilities, no recourse | 28,400 | 32,200 |
VIE Non-current liabilities, no recourse | $ 2,600 | $ 26,000 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | ||||
Revenues: | ||||||
Revenues | $ 133,528 | [1] | $ 276,957 | [2] | $ 674,634 | [3] |
Operating costs: | ||||||
Operating costs | 81,277 | 237,546 | 384,728 | |||
Depreciation, depletion, and amortization | 27,962 | 115,496 | 275,573 | |||
Impairments (Note 4) | 26,063 | [4] | 867,814 | [5] | 625,716 | [6] |
General and administrative | 6,702 | 42,766 | 38,246 | |||
(Gain) loss on disposition of assets | (619) | (89) | 3,502 | |||
Total operating expenses | 141,385 | 1,282,266 | 1,327,765 | |||
Income (loss) from operations | (7,857) | (1,005,309) | (653,131) | |||
Other income (expense): | ||||||
Interest, net | (3,275) | (22,824) | (37,012) | |||
Gain (loss) on derivatives | (985) | (10,704) | 4,225 | |||
Other | 100 | 2,034 | (236) | |||
Total other income (expense) | (6,433) | 100,055 | (33,023) | |||
Loss before income taxes | (14,290) | (905,254) | (686,154) | |||
Income tax benefit: | ||||||
Current | (302) | (917) | (1,281) | |||
Deferred | 0 | (13,713) | (131,045) | |||
Total income taxes | (302) | (14,630) | (132,326) | |||
Net loss | (13,988) | (890,624) | (553,828) | |||
Net income attributable to non-controlling interest | 4,152 | 40,388 | 51 | |||
Net loss attributable to Unit Corporation | $ (18,140) | $ (931,012) | $ (553,879) | |||
Net loss attributable to Unit Corporation per common share (Note 7): | ||||||
Basic | $ (1.51) | $ (17.45) | $ (10.48) | |||
Diluted | $ (1.51) | $ (17.45) | $ (10.48) | |||
Loss on abandonment of assets | $ 0 | $ 18,733 | $ 0 | |||
Write off of Deferred Debt Issuance Cost | 0 | (2,426) | 0 | |||
Reorganization Items | (2,273) | 133,975 | 0 | |||
Oil and Natural Gas | ||||||
Revenues: | ||||||
Revenues | 57,578 | [1] | 103,439 | [2] | 325,797 | [3] |
Operating costs: | ||||||
Operating costs | 25,256 | 117,691 | 135,124 | |||
Contract drilling | ||||||
Revenues: | ||||||
Revenues | 19,413 | [1] | 73,519 | [2] | 168,383 | [3] |
Operating costs: | ||||||
Operating costs | 13,852 | 51,810 | 115,998 | |||
Gas gathering and processing | ||||||
Revenues: | ||||||
Revenues | 56,537 | [1] | 99,999 | [2] | 180,454 | [3] |
Operating costs: | ||||||
Operating costs | $ 42,169 | $ 68,045 | $ 133,606 | |||
[1] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | |||||
[2] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | |||||
[3] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | |||||
[4] | During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax | |||||
[5] | During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. | |||||
[6] | We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | |||
Net loss | $ (13,988) | $ (890,624) | $ (553,828) |
Other comprehensive income (loss), net of taxes: | |||
Reclassification adjustment for write-down of securities, net of tax | 0 | 0 | 481 |
Reclassification Adjustment from AOCI for Write-down of Securities, Tax | 0 | 0 | (47) |
Comprehensive loss | (13,988) | (890,624) | (553,347) |
Less: Comprehensive income attributable to non-controlling interest | 4,152 | 40,388 | 51 |
Comprehensive loss attributable to Unit Corporation | $ (18,140) | $ (931,012) | $ (553,398) |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands | Total | Common Stock | Capital In Excess of Par Value | Accumulated Other Comprehensive Loss | Retained Earnings | Non-controlling Interest in Consolidated Subsidiaries |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Cumulative effect adjustment for adoption of ASUs | $ 174 | $ 0 | $ 0 | $ 0 | $ 174 | $ 0 |
Beginning balance at Dec. 31, 2018 | 1,593,444 | 10,414 | 628,108 | (481) | 752,840 | 202,563 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net loss | (553,828) | 0 | 0 | 0 | (553,879) | 51 |
Reclassification Adjustment from AOCI for Write-down of Securities, Tax | (47) | |||||
Other comprehensive income (loss) | 481 | 0 | 0 | 481 | 0 | 0 |
Total comprehensive income (loss) | (553,347) | |||||
Distribution to non-controlling interest | (918) | 0 | 0 | 0 | 0 | (918) |
Activity in employee compensation plans | 16,282 | 177 | 16,044 | 0 | 0 | 61 |
Ending balance at Dec. 31, 2019 | 1,055,635 | 10,591 | 644,152 | 0 | 199,135 | 201,757 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net loss | (890,624) | 0 | 0 | 0 | (931,012) | 40,388 |
Reclassification Adjustment from AOCI for Write-down of Securities, Tax | 0 | |||||
Total comprehensive income (loss) | (890,624) | |||||
Activity in employee compensation plans | 6,169 | 113 | 6,001 | 0 | 0 | 55 |
Ending balance at Aug. 31, 2020 | 171,180 | 10,704 | 650,153 | 0 | (731,877) | 242,200 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of Successor equity | 197,323 | 120 | 197,203 | 0 | 0 | 0 |
Ending balance at Sep. 01, 2020 | 439,523 | 120 | 197,203 | 0 | 0 | 242,200 |
Beginning balance at Aug. 31, 2020 | 171,180 | 10,704 | 650,153 | 0 | (731,877) | 242,200 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net loss | (13,988) | 0 | 0 | 0 | (18,140) | 4,152 |
Reclassification Adjustment from AOCI for Write-down of Securities, Tax | 0 | |||||
Total comprehensive income (loss) | (13,988) | |||||
Activity in employee compensation plans | 58 | 0 | 39 | 0 | 0 | 19 |
Ending balance at Dec. 31, 2020 | $ 425,593 | $ 120 | $ 197,242 | $ 0 | $ (18,140) | $ 246,371 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | ||||
OPERATING ACTIVITIES: | ||||||
Net loss | $ (13,988) | $ (890,624) | $ (553,828) | |||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||
Depreciation, depletion, and amortization | 27,962 | 115,496 | 275,573 | |||
Impairments (Note 4) | 26,063 | [1] | 867,814 | [2] | 625,716 | [3] |
Loss on abandonment of assets | 0 | 18,733 | 0 | |||
Amortization of debt issuance costs and debt discount (Note 9) | 0 | 1,079 | 2,241 | |||
(Gain) loss on derivatives (Note 15) | 985 | 10,704 | (4,225) | |||
Cash receipts (payments) on derivatives settled (Note 15) | (1,133) | (4,244) | 16,196 | |||
(Gain) loss on disposition of assets | (619) | (89) | 3,502 | |||
Write-off of debt issuance costs | 0 | 2,426 | 0 | |||
Deferred tax benefit (Note 11) | 0 | (13,713) | (131,045) | |||
Employee stock compensation plans | 58 | 4,786 | 12,932 | |||
Bad debt expense | 0 | 3,155 | 527 | |||
ARO liability accretion (Note 10) | 467 | 1,545 | 2,343 | |||
Contract assets and liabilities, net (Note 5) | 1,316 | 2,459 | (2,577) | |||
Noncash reorganization items | 67 | (138,797) | 0 | |||
Other, net | (3,046) | 12,164 | 1,766 | |||
Changes in operating assets and liabilities increasing (decreasing) cash: | ||||||
Accounts receivable | (7,226) | 28,880 | 33,323 | |||
Materials and supplies | 0 | 89 | 24 | |||
Prepaid expenses and other | 1,795 | (3,849) | 195 | |||
Accounts payable | 1,484 | (18,381) | (15,558) | |||
Accrued liabilities | (4,048) | 44,811 | 3,142 | |||
Income taxes | (301) | 906 | 298 | |||
Contract advances | (29) | (394) | (1,149) | |||
Net cash provided by operating activities | 29,807 | 44,956 | 269,396 | |||
INVESTING ACTIVITIES: | ||||||
Capital expeditures | (4,057) | (25,775) | (406,665) | |||
Producing property and other oil and natural gas acquisitions | 0 | (382) | (3,653) | |||
Payments to Acquire Other Property, Plant, and Equipment | 0 | 0 | (16,109) | |||
Proceeds from disposition of property and equipment | 1,799 | 6,018 | 31,864 | |||
Net cash used in investing activities | (2,258) | (20,139) | (394,563) | |||
FINANCING ACTIVITIES: | ||||||
Borrowings under line of credit | 0 | 87,400 | 493,500 | |||
Payments under line of credit | (49,000) | (64,100) | (368,800) | |||
DIP financing costs | 0 | (990) | 0 | |||
Exit facility financing costs | 0 | (3,225) | 0 | |||
Net payments on finance leases | (1,406) | (2,757) | (4,001) | |||
Proceeds from investments of non-contolling interests | 0 | 0 | 0 | |||
Employee taxes paid by withholding shares | 0 | (43) | (4,158) | |||
Transaction costs associated with sale of non-controlling interest | 0 | 0 | 0 | |||
Distributions to non-controlling interest | 0 | 0 | (918) | |||
Bank overdrafts (Note 4) | 2,631 | (8,733) | 3,663 | |||
Net Cash Provided by (Used in) Financing Activities, Total | (47,775) | 7,552 | 119,286 | |||
Net increase (decrease) in cash and cash equivalents | (20,226) | 32,369 | (5,881) | |||
Cash, restricted cash, cash equivalents, beginning of year | 32,940 | 571 | 6,452 | |||
Cash, restricted cash, cash equivalents, end of year | 12,714 | 32,940 | 571 | |||
Supplemental disclosure of cash flow information: | ||||||
Interest paid (net of capitalization) | 2,571 | 6,417 | 33,694 | |||
Income taxes | 0 | 0 | 273 | |||
Reorganization items | 2,206 | 4,822 | 0 | |||
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment | 1,902 | 8,561 | 54,549 | |||
Non-cash reductions to oil and natural gas properties related to asset retirement obligations | 1,702 | 29,189 | (76) | |||
Non-cash trade of property, plant, and equipment | $ 0 | $ 1,403 | $ 0 | |||
[1] | During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax | |||||
[2] | During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. | |||||
[3] | We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). |
Organization
Organization | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | ORGANIZATION Unless the context clearly indicates otherwise, references in this report to “Unit”, “company”, “we”, “our”, “us”, or like terms refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior of which we own 50%. We are primarily engaged in the development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are all in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream. Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Utah, and Wyoming. Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, we drill onshore oil and natural gas wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are mainly in Oklahoma, Texas, New Mexico, Wyoming, North Dakota, and to a lesser extent in Colorado. Mid-Stream. Carried out by our subsidiary, Superior, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. |
Emergence from Voluntary Reorga
Emergence from Voluntary Reorganization Under Chapter 11 | 12 Months Ended |
Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Emergence from Voluntary Reorganization Under Chapter 11 [Text Block] | EMERGENCE FROM VOLUNTARY REORGANIZATION UNDER CHAPTER 11 Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code On May 22, 2020, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were jointly administered under Case No. 20-32740 (DRJ). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court and under the Bankruptcy Code. On August 6, 2020, the bankruptcy court entered the “Findings of Fact, Conclusions of Law, and Order (I) approving the Disclosure Statement on a Final Basis and (II) confirming the Plan on a final basis. On September 3, 2020, the conditions to effectiveness for the Plan were satisfied, and the Debtors emerged from Chapter 11. Following emergence, we implemented the Plan as follows: • Each lender under the (i) the Unit credit agreement, and (ii) the DIP Credit Agreement received (or was entitled to receive) its pro rata share of revolving loans, term loans, and letter of credit participations under the Exit Credit Agreement, in exchange for the lender’s allowed claims under the Unit credit agreement or DIP Credit Agreement; • Each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described below); • The company issued a total of 12.0 million shares of New Common Stock at a par value of $0.01 per share to be subsequently distributed in accordance with the Plan; • Each holder of the Notes received its pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim; • Each holder of an allowed general unsecured claim against Unit or UPC was entitled to receive its pro rata share of New Common Stock based on equity allocations at each of Unit and UPC, respectively; • A disputed claims reserve was established for distribution of New Common Stock on allowance of certain disputed general unsecured claims; • Each holder of an allowed general unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA received payment or will receive payment in full for that claim in the ordinary course of business; and • Each retained or former employee with a claim for vested severance benefits, who opted into a settlement, received or will receive cash payment(s) for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims. On December 11, 2020, approximately 10.5 million shares of New Common Stock were distributed to the holders of the Notes entitled to receive their pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim. The remaining 0.9 million shares are being held for the Disputed Claims Reserve. All shares of New Common Stock are subject to the transfer restrictions in the company’s Amended and Restated Certificate of Incorporation (Charter). Article XIV of the Charter provides that, subject to the exceptions provided in Article XIV, any attempted transfer of the New Common Stock will be prohibited and void ab initio if (i) because of the transfer, any person becomes a Substantial Stockholder (as defined below) other than by reason of Treasury Regulations section 1.382-2T(j)(3) or (ii) the Percentage Stock Ownership (as defined in the Charter) interest of any Substantial Stockholder will be increased. A “Substantial Stockholder” means a person with a Percentage Stock Ownership of 4.75% or more. Warrants Each holder of the company’s Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, may receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. The Warrants will expire on the earliest of (i) September 3, 2027, (ii) the consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant not exercised by the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. On December 21, 2020, the company issued approximately 1.8 million Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares of Old Common Stock in street name through the facilities of the DTC. On February 11, 2021, we issued approximately 43,000 Warrants to certain holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). The company expects to issue approximately 37,000 more Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through Direct Registration. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive such holder’s distribution of Warrants. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date. Events of Default The filing of the Chapter 11 Cases constituted an event of default that accelerated the company's obligations under the Unit credit agreement and the indenture governing the Notes. Additionally, other events of default, including cross-defaults, existed, or occurred under these debt agreements. The amounts owed regarding the Notes were classified as liabilities subject to compromise. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the company. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the Superior credit agreement. In addition, the Debtors' filing of the bankruptcy petitions constituted a termination event under the Debtors' hedge agreements, which allowed the counterparties to those hedge agreements to terminate the outstanding hedges, as those termination events were not stayed by the Chapter 11 Cases. On filing the Chapter 11 Cases, Unit entered into a Continuation Agreement (Continuation Agreement) with Superior, SPC Midstream Operating, L.L.C., and SP Investor to continue the parties' contractual relationships during the Chapter 11 Cases under the governance, operational, and related agreements entered into by those parties at the formation of the company’s midstream joint venture with SP Investor, which agreements contained certain provisions that otherwise would have been triggered by filing the Chapter 11 Cases. Liquidity, Unit Credit Facility, and Debtor-in-Possession Credit Agreement To provide liquidity to fund our operations and the Chapter 11 Cases, the Debtors entered into the DIP Credit Agreement. Before repayment and termination on the Effective Date, borrowings under the DIP Credit Agreement would have matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP lenders), (ii) the sale of all or substantially all the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, and (v) the date of termination of the DIP lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP Credit Agreement and subject to the bankruptcy court’s orders. On the Effective Date, the DIP Credit Agreement was repaid in full and terminated. Following the Debtors’ emergence from the Chapter 11 Cases, each holder of an allowed claim under the DIP Credit Agreement received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the Exit Credit Agreement. In addition, each holder received or was entitled to receive its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants). Going Concern At June 30, 2020, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raised substantial doubt about the company’s ability to continue as a going concern. The company, therefore, concluded as of that date there was substantial doubt about the company’s ability to continue as a going concern. The company implemented changes that (i) minimized capital expenditures, (ii) aggressively managed its working capital, and (iii) reduced recurring operating expenses. As a result of those changes and the successful reorganization of our long term debt, we determined that there is no longer substantial doubt about the company's ability to continue operating as a going concern for a period of at least one year. Exit Credit Agreement On the Effective Date, under the Plan, we entered into an amended and restated credit agreement (Exit Credit Agreement). Refer to Note 9 – Long-Term Debt and Other Long-Term Liabilities for the terms of the Exit Credit Agreement. Interest Expense The Debtors discontinued recording interest on liabilities subject to compromise as of the filing of the Chapter 11 Cases. Contractual interest on liabilities subject to compromise not reflected in the Consolidated Statements of Operations for the eight months ended August 31, 2020 was approximately $12.4 million, respectively, representing interest expense from the filing date through August 31, 2020. In addition, the Debtors did not make the May 15, 2020 $21.5 million required interest payment on the Notes. |
Fresh Start Accounting
Fresh Start Accounting | 12 Months Ended |
Dec. 31, 2020 | |
Reorganizations [Abstract] | |
Fresh Start Accounting Disclosure | FRESH START ACCOUNTING On the Effective Date, the company qualified for and adopted fresh start accounting under the provisions in FASB Topic ASC 852, Reorganizations , as (i) the Reorganization Value of the company’s assets immediately before the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the Old Common Stock received less than 50% voting shares of the Successor. Refer to Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 for the terms of the Plan. Reorganization Value Reorganization value, as determined under ASC 820, Fair Value Measurement , represents the fair value of the Successor's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value was derived from the Successor's enterprise value, which represents the estimated fair value of an entity’s long-term debt and equity. The Successor’s enterprise value, confirmed by the bankruptcy court, was estimated to be within a range of $270.0 million to $380.0 million, with a midpoint of $325.0 million. Based on the estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $317.0 million before consideration of cash and cash equivalents, restricted cash and outstanding debt at the Effective Date. As a result, the reorganization value was determined to be $726.3 million at the Effective Date, as reconciled below. We estimated the enterprise value of the Successor using three valuation methods: net asset value (NAV), comparable public company analysis, and discounted cash flow (DCF). The NAV is a looking forward methodology under which future cash flows are discounted using various discount rates depending on reserve category. Similarly, DCF projects future cash flows which are discounted at rates above and below the company’s estimated weighted average cost of capital. The comparable public company analysis is based on the enterprise values of selected public companies with operating and financial characteristics comparable to the company. Under this methodology, certain financial multiples that measure financial performance and value are calculated for each selected company and then applied to imply an estimated enterprise value of the company. The following table reconciles the enterprise value to the estimated fair value of the Successor's equity at the Effective Date (in thousands): Enterprise value $ 559,205 Less: Fair value of noncontrolling interest (242,200) Enterprise value of Unit interests 317,005 Plus: Cash and cash equivalents 25,482 Plus: Restricted cash 7,458 Less: Fair value of capital leases (4,622) Less: Fair value of debt (including the fair value of current debt) (148,000) Fair value of Successor equity $ 197,323 The following table reconciles the enterprise value to the reorganization value of the Successor’s assets as of the Effective Date (in thousands): Enterprise value $ 559,205 Plus: Cash and cash equivalents 25,482 Plus: Restricted cash 7,458 Plus: Current liabilities (excluding the fair value of capital leases and current debt) 86,897 Plus: Long-term asset retirement obligation 22,415 Plus: Other long-term liabilities (excluding long-term asset retirement obligation) 24,886 Reorganization value of Successor assets $ 726,343 Although we believe the assumptions and estimates used to develop the Enterprise Value and the Reorganization Value were reasonable and appropriate, different assumptions and estimates would materially impact the analysis and our resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require significant judgment. Valuation Process Oil and Natural Gas Properties Our oil and natural gas properties are accounted for under the full cost accounting method. We determined the fair value of our oil and gas properties based on the anticipated cash flows associated with our proved reserves and discounted those cash flows using a weighted average cost of capital rate of 13.5%. The discount rate is commonly based on empirical studies of investment rates of return of publicly traded equity securities with investment return and risk characteristics similar to the subject company, which follows a market-based approach. Weighted average commodity prices used in determining the fair value of oil and natural gas properties were $48.98 per barrel of oil, $2.68 per million cubic feet of natural gas and $18.51 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices. Our unproved acreage was determined to have no value due to the capital constraints contained in our debt agreement along with our plans to not drill in our proved reserves cash flows. Our salt water disposal assets were included in the cash flows of the proved reserves forecast, therefore, those values are included in the total value of our proved properties. Drilling Equipment The value of our drilling rigs in operation (approximately $37.0 million) was estimated using an income-based approach using discounted free cash flows over the remaining useful lives of the drilling rigs. Anticipated cash flows associated with operating drilling rigs were discounted using a weighted average cost of capital rate of 13.8% for five years with a terminal value at the conclusion of the forecast period. The fair value of our non-operating drilling rigs, and other related drilling equipment (approximately $26.5 million), was valued using a market-based approach with varying ranges of economic obsolescence rates to adjust for the impact of the oil and gas downturn. Land and Building Our corporate headquarters building in Tulsa, Oklahoma was completed in May 2016 and resides on approximately 30 acres. To determine its fair value, we used a market-based approach based on comparable tenant rates in our area. Gas Gathering and Processing Equipment, Transportation Equipment, and Other Property Gas gathering and processing equipment, transportation equipment and other equipment was valued using a market-based approach estimating what a market participant would pay for similar equipment in an orderly transaction. We used varying ranges of economic obsolescence rates depending on the underlying asset group. For pipelines and right-of-ways, we used a value per acre based on the location of the asset and estimated an average value of $129 per rod. We then applied an economic obsolescence rate of approximately 64% to determine the ultimate fair value. Unit's Investment in Superior To determine the net equity value of our investment in Superior, we simulated paths for Superior's total equity value through the expected liquidation date, where we simulated equity value using a Geometric Brownian Motion (GBM). The expected value (i.e., average of all simulations) of each security class was discounted to present value using the concluded risk-free rate to conclude on the respective allocated values. Consolidated Balance Sheet The adjustments included in the following Consolidated Balance Sheets reflect the effect of the transactions contemplated by the Plan (reflected in the column "Reorganization Adjustments") and fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column "Fresh Start Adjustments"). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions. As of September 1, 2020 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments (11) Successor ASSETS (In thousands) Current assets: Cash and cash equivalents $ 32,280 $ (6,798) (2) $ — $ 25,482 Restricted cash — 7,458 (3) — 7,458 Accounts receivable, net 50,621 — — 50,621 Materials and supplies 64 — (64) (12) — Current income tax receivable 850 — — 850 Prepaid expenses and other 13,692 6,382 (4) (990) (13) 19,084 Total current assets 97,507 7,042 (1,054) 103,495 Property and equipment: Oil and natural gas properties, on the full cost method: Proved properties 6,539,816 — (6,301,532) (14) 238,284 Unproved properties not being amortized 30,205 — (30,205) (14) — Drilling equipment 1,285,024 — (1,221,566) (15) 63,458 Gas gathering and processing equipment 833,788 — (583,690) (15) 250,098 Saltwater disposal systems 43,541 — (43,541) (15) — Land and building 59,080 — (26,445) (15) 32,635 Transportation equipment 15,577 — (12,263) (15) 3,314 Other 57,427 — (47,469) (15) 9,958 8,864,458 — (8,266,711) 597,747 Less accumulated depreciation, depletion, amortization, and impairment 7,923,868 — (7,923,868) (14) (15) — Net property and equipment 940,590 — (342,843) 597,747 Right of use asset 7,476 — (659) (16) 6,817 Other assets 24,666 (6,382) (4) — 18,284 Total assets $ 1,070,239 $ 660 $ (344,556) $ 726,343 As of September 1, 2020 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments (11) Successor LIABILITIES AND SHAREHOLDERS’ EQUITY (In thousands) Current liabilities: Accounts payable $ 27,354 $ 6,382 (4) $ — $ 33,736 Accrued liabilities 36,990 (4,115) (5) — 32,875 Current operating lease liability 4,643 — (669) (16) 3,974 Current portion of long-term debt 124,000 (123,600) (6) — 400 Current derivative liabilities 5,089 — — 5,089 Warrant liability — — 885 (17) 885 Current portion of other long-term liabilities 11,201 3,743 (7) 16 (18) 14,960 Total current liabilities 209,277 (117,590) 232 91,919 Long-term debt 16,000 131,600 (6) — 147,600 Non-current derivative liabilities 766 — — 766 Operating lease liability 2,760 — 11 (16) 2,771 Other long-term liabilities 61,393 (3,220) (4) (7) (14,409) (18) 43,764 Liabilities subject to compromise 762,215 (762,215) (8) — — Deferred income taxes 4,466 — (4,466) (19) — Commitments and contingencies Shareholders’ equity: Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019 — — — — Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019 10,704 (10,704) (9) — — Predecessor capital in excess of par value 650,153 (650,153) (9) — — Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 1, 2020 — — — — Successor common stock, $0.01 par value, 25,000,000 authorized, 12,000,000 issued at September 1, 2020 — 120 (8) — 120 Successor capital in excess of par value — 197,203 (8) — 197,203 Retained earnings (deficit) (818,679) 1,215,619 (10) (396,940) (20) — Total shareholders’ equity attributable to Unit Corporation (157,822) 752,085 (396,940) 197,323 Non-controlling interests in consolidated subsidiaries 171,184 — 71,016 (21) 242,200 Total shareholders' equity 13,362 752,085 (325,924) 439,523 Total liabilities and shareholders’ equity $ 1,070,239 $ 660 $ (344,556) $ 726,343 Reorganization Adjustments (1) Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes. (2) The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands): Funding of the professional fees escrow account $ (7,458) Proceeds from Exit credit facility 8,000 Payment of debt issuance costs on the Exit credit facility (3,225) Payment of professional fees (3,943) Payment of accrued interest payable under the Predecessor credit facility (172) Changes in cash and cash equivalents $ (6,798) (3) Represents the reserve for professional fee escrow of $7.5 million. (4) Represents the reclassification of other long-term assets related to deferred compensation to prepaid expenses and other assets as the deferred compensation payout must be paid within 12 months from the date of emergence under the Plan. Simultaneously, the current portion of deferred compensation liability was reclassified from other long-term liabilities to accounts payable. (5) Represents the payment of the DIP facility interest of $0.2 million and professional fees for $3.9 million. (6) Represents the transition of the DIP Credit Agreement and the Predecessor Credit Agreement of $124.0 million into the Exit Facility and issuing an additional $8.0 million of borrowings under the Exit Credit Agreement. (7) Represents the reclassification of the short-term portion of the separation benefit liabilities from non-current to current liabilities which was offset by the increase in non-current portion of liabilities. (8) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands): Liabilities subject to compromise before the Effective Date: 6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date) $ 672,369 Accounts payable 1,179 Employee separation benefit plan obligations 23,394 Litigation settlements 45,000 Royalty suspense accounts payable 20,273 Total liabilities subject to compromise 762,215 Separation settlement treatment (6,905) Successor Common Stock and APIC (1) issued to allowed claim holders (175,521) Successor Common Stock and APIC for disputed claims reserve (11,936) Gain on settlement of liabilities subject to compromise $ 567,853 (1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise. (9) Represents the cancellation of Old Common Stock. (10) Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above. Fresh Start Adjustments (11) Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below. (12) Represents the reclassification of materials and supplies to proved properties. (13) Represents the write off of the Predecessor's unamortized debt fees related to the DIP facility. (14) Reflects a decrease of oil and natural gas properties, net, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Proved properties $ 238,284 $ 6,539,816 Unproved properties — 30,205 238,284 6,570,021 Less accumulated depletion, amortization, and impairment — (6,305,113) $ 238,284 $ 264,908 (15) Reflects a decrease in fair value of drilling equipment, gas gathering and processing equipment, saltwater disposal systems, land and building, transportation equipment, and other property and equipment and the elimination of accumulated depreciation, based on the methodologies discussed above. The following table summarizes the components of other property and equipment as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Drilling equipment $ 63,458 $ 1,285,024 Gas gathering and processing equipment 250,098 833,788 Saltwater disposal systems — 43,541 Land and building 32,635 59,080 Transportation equipment 3,314 15,577 Other 9,958 57,427 359,463 2,294,437 Less accumulated depreciation and impairment — (1,618,754) $ 359,463 $ 675,683 (16) Reflects the valuation adjustments to the company’s right of use assets, current operating lease liability, and operating lease liability, adjusted for fair value of favorable and unfavorable lease terms, and the revised incremental borrowing rates of the Successor. (17) Represents the liability for the Warrants using a Black-Scholes-Merton model which uses various market-based inputs including: stock prices, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield. (18) Represents the reclassification of the short-term portion of ARO from non-current liabilities to current and the fair value adjustment, which was determined using our fresh start updates to these obligations, including the application of the Successor's credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of well plugging activity, and resetting all ARO to a single layer. (19) Represents the adjustments to deferred tax liability as a result of the cumulative tax impact of the fresh start adjustments. The significant revisions to the carrying value of our assets and liabilities because of applying fresh start accounting resulted in the company increasing its overall net deferred tax asset position on emergence from bankruptcy. Besides the changes in book value, the company has as of the Effective Date, approximately $726.4 million of net operating losses (NOLs) carried forward to offset taxable income in the future years. Approximately $584.2 million of this NOL will expire commencing in fiscal 2021 through 2037. The NOLs of approximately $142.2 million from years ended after December 31, 2017 have an indefinite carryforward period. The amount of these NOLs which is available to offset future income may be severely limited due to change-in-control tax provisions. Because of our history of operating losses and the uncertainty surrounding the realization of the deferred tax assets in future years, we have determined that it is more likely than not that the deferred tax assets will not be realized in future periods. Accordingly, we recorded a 100% valuation allowance against our net deferred tax assets. (20) Represents the cumulative impact of the fresh start accounting adjustments discussed above. (21) The valuation of the non-controlling interest was calculated by taking an income-based approach in valuing Superior. The value of the non-controlling interest was then determined based on a market-based approach for similar type investments, given the contractual rights of the related parties. Reorganization Items. As described below in Note 4 – Summary Of Significant Accounting Policies, our Consolidated Statements of Operations for the periods ended August 31, 2020 and December 31, 2020 include "Reorganization items, net," which reflects gains recognized on the settlement of liabilities subject to compromise and costs and other expenses associated with the Chapter 11 proceedings, primarily professional fees, and the costs associated with the DIP Credit Agreement. These post-petition costs for professional fees, and administrative fees charged by the U.S. trustee, have been reported in "Reorganization items, net" in our Consolidated Statements of Operations as described above. Similar costs were incurred during the pre-petition period have been reported in "General and administrative" expenses. The following table summarizes the components included in "Reorganization items, net" in our Consolidated Statements of Operations for the periods presented: Successor Predecessor Four Months Ended Eight Months Ended December 31, 2020 August 31, (In thousands) Gains on settlement of liabilities subject to compromise $ — $ (567,853) Fresh start accounting adjustments — 401,406 Legal and professional fees and expenses 2,273 15,745 Acceleration of Predecessor stock compensation expense — 1,431 Exit Facility fees — 3,225 5% Exit Facility equity fee — 9,866 Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021 — 2,205 Total reorganization items, net $ 2,273 $ (133,975) |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidate the activities of Superior, a 50/50 joint venture between Unit and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 19 – Variable Interest Entity Arrangements. Effective at emergence, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our Consolidated Statements of Operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements. Fresh Start Accounting. The consolidated financial statements in Note 3 - Fresh Start Accounting have been prepared in accordance with Financial Accounting Standard Board (FASB) ASC Topic 852, Reorganizations . We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting Date) would not have a material impact to the consolidated financial statements. This was reflected in our Consolidated Balance Sheets as of September 1, 2020. Accordingly, our consolidated financial statements and notes after September 1, 2020, are not comparable to the consolidated financial statements and notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor. We have applied the relevant guidance provided in U.S. GAAP regarding the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and reorganized as going concerns in preparing the consolidated financial statements and notes through the period ended August 31, 2020, or the Predecessor Period. That guidance requires, for periods after our bankruptcy filing on May 22, 2020, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain expenses, realized gains, and losses and provisions that were realized or incurred in the Chapter 11 Cases have been included in "Reorganization items, net" on our Consolidated Statements of Operations. In addition, certain liabilities and other obligations incurred before May 22, 2020, or pre-petition periods, have been classified as "Liabilities subject to compromise" on our Predecessor Consolidated Balance Sheets through August 31, 2020. See Note 3 – Fresh Start Accounting for further detail. Accounting Estimates. Preparing financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Drilling Contracts. Because we not do bear the risk of completion of the well, we recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed. Typically, this type of contract can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2020, all our contracts were daywork contracts of which five were multi-well and had durations which ranged from two months to one year, three of which expire in 2021 and two expiring in 2022. These longer-term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate. Cash Equivalents and Bank Overdrafts. We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Bank overdrafts are checks issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2020 and 2019, bank overdrafts were $2.6 million and $8.7 million, respectively. Accounts Receivable. Accounts receivable is carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful. Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to our receivables. Our credit risk is considered limited due to the many customers comprising our customer base. Below are the third-party customers that accounted for over 10% of each of our segment’s revenues: Successor Predecessor Period Period For the Year Ended Oil and Natural Gas: CVR Refining, LP 14 % 15 % 14 % Plains Marketing L.P. * 11 % * Drilling: EOG Resources, Inc. 28 % 20 % 12 % QEP Resources, Inc. 23 % 10 % 12 % Citizen Energy III, LLC 16 % * * Slawson Exploration Company, Inc. 16 % 21 % 11 % Cimarex Energy Co. 12 % * * Mid-Stream: ONEOK, Inc. 28 % 31 % 33 % Range Resources Corporation 15 % 21 % 13 % Centerpoint Energy Service, Inc. * * 10 % _______________________ * Revenue accounted for less than 10% of the segment's revenues. We had a concentration of cash of $21.4 million and $1.7 million at December 31, 2020 and 2019, respectively with one bank. Using derivative transactions also involves the risk that the counterparties cannot meet the financial terms of the transactions. We considered this non-performance risk regarding our counterparties and our own non-performance risk in our derivative valuation at December 31, 2020 and determined there was no material risk at that time. At December 31, 2020, the fair values of the net liabilities we had with each of the counterparties regarding our commodity derivative transactions are listed in the table below: December 31, 2020 (In millions) Bank of Oklahoma $ (5.4) Bank of Montreal (0.3) Total net liabilities $ (5.7) Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Prior to emergence from bankruptcy, we recorded depreciation of drilling equipment using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle, unless idle for greater than 48 months, then it was depreciated at the full active rate. We also used the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage drilled compared to total estimated remaining footage. As of emergence, we elected to depreciate all drilling assets utilizing the straight-line method over the useful lives of the assets ranging from four to ten years. Depreciation on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years. We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets. At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $407.1 million in the first quarter of 2020. We also recorded an additional non-cash impairment charge of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairment charge in our Consolidated Statements of Operations. We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management’s best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future. We concluded that no impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately $242.5 million at March 31, 2020. The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin, which means minor changes in certain key assumptions in future periods may result in material impairment charges in future periods. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values. We recorded expense of $1.1 million related to the write-down of certain equipment in the third quarter of 2020 that we now consider abandoned. These amounts are reported in loss on abandonment of assets in our Consolidated Statements of Operations. During the third quarter of 2019, we determined a triggering event had occurred within our contract drilling segment due to a decline in the number of drilling rigs being used and the overall market performance of the contract drilling industry. As a result, we performed a recoverability test on long-lived assets within that segment. Based on the results of the undiscounted future cash flows of that asset group, the undiscounted projected future cash flows of the asset group exceeded the group's carrying value as of September 30, 2019 and therefore no long-lived asset impairment was recorded for the group. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation. For our gas gathering and processing systems, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Consolidated Statement of Operations. Capitalized Interest. During 2019, interest of approximately $16.2 million was capitalized based on the net book value associated with unproved oil and gas properties not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest in 2020. Goodwill. Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed annually to determine whether the fair value has decreased or additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, using discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. Due to the triggering event within the contract drilling segment, we performed an interim goodwill impairment test as of September 30, 2019. Based on the projected discounted cash flows, we recognized a goodwill impairment charge of $62.8 million, pre-tax ($59.8 million, net of tax) which represented total goodwill we previously reported on our Consolidated Balance Sheets. There were no additions to goodwill in 2020 or 2019. Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. All productive and non-productive costs incurred in connection with the acquisition, exploration, and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs. Directly related overhead costs of $16.5 million were capitalized in 2019. We did not capitalize any directly related overhead costs in 2020. Capitalized costs are amortized on a units-of-production method based on proved oil and natural gas reserves. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. The average rates used for DD&A were $4.21, $7.77, and $9.66 per Boe in the Successor Period of 2020, the Predecessor Period of 2020, and for the year 2019, respectively. During the fourth quarter 2019, we reassessed estimated salvage values associated with our oil and natural gas operations. Based on market conditions for our industry and the substantial doubt that existed for our ability to continue as a going concern, we revised these estimates downward for a total adjustment of $39.7 million ($25.6 million discounted for our full cost ceiling test) to salvage value estimates. No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties. Successor Period Impairments . As of September 1, 2020, we adopted fresh start accounting and adjusted our assets to fair value. Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in non-cash ceiling test write-downs of $26.1 million pre-tax for Successor Period primarily due to the use of average 12-month historical commodity prices for the ceiling test versus forward prices for our Fresh Start fair value estimates. It is hard to predict with any certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2020, and only adjust the 12-month average price as of March 2021, our forward-looking expectation is that we will not recognize an impairment in the first quarter of 2021. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination. Predecessor Period Impairments. We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $226.5 million and $73.9 million in 2020 and 2019, respectively, of costs being added to the total of our capitalized costs being amortized. We recorded non-cash ceiling test write-downs of $393.7 million pre-tax ($346.6 million, net of tax) in the Predecessor Period of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. We incurred non-cash ceiling test write-downs of $559.4 million pre-tax ($422.4 million, net of tax) in 2019. In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of the use of those assets, we determined that some of those assets were no longer expected to be used and we wrote off those salt water disposal assets that we now consider abandoned. We recorded total expense of $17.6 million related to the write-down of those salt water disposal assets for the eight months ended August 31, 2020. These amounts are reported in loss on abandonment of assets in our Consolidated Statements of Operations. Our contract drilling segment provides drilling services for our oil and natural gas segment. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated $1.6 million of intercompany profit during 2019 as a reduction to the carrying value of our oil and natural gas properties. We did not eliminate any profit in 2020 due to no drilling services being provided during the period. ARO. We record the fair value of liabilities associated with the future plugging and abandonment of our wells. When the reserves in each of our oil or gas wells becoming fully depleted or otherwise become uneconomical, we incur costs to plug and abandon the wells. These future costs are recorded at the time the wells are drilled or acquired. We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool. Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums. Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. Cash settlements received or paid for matured, early-terminated, and modified derivatives are reported in cash receipts (payments) on derivatives settled in our Consolidated Statements of Cash Flows. We do not engage in derivative transactions solely for speculative purposes. Limited Partnerships. Unit Petroleum Company was a general partner in 13 oil and natural gas limited partnerships. Some of our officers, directors, and employees owned the interests in most of these partnerships. We shared in each partnership’s revenues and costs under formulas set out in the limited partnership agreement. The partnerships also reimbursed us for certain administrative costs incurred on behalf of the partnerships. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest. Income Taxes. Measurement of net deferred tax liabilities is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where needed to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities. The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Natural Gas Balancing. We account for revenue transactions under ASC 606 for recording natural gas sales, which may be more or less than our share of pro-rata production from certain wells. We estimate our December 31, 2020 balancing position to be approximately 3.3 Bcf on under-produced properties and approximately 3.3 Bcf on over-produced properties. We have recorded a receivable of $3.4 million on certain wells where we estimate that insufficient reserves are available for us to recover our under-production from future production volumes. We have also recorded a liability of $4.0 million on certain properties where there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material. Employee and Director Stock Based Compensation. We recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. Our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We used the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants was based on the closing stock price on the date of the grants. On the Effective Date, all unvested restricted stock and un-exercised stock options were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. See Note 14 – Stock-Based Compensation for further detail. New Accounting Standards Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The amendments will not have a material impact on our consolidated financial statements. Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments will be effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. This standard will not have a material impact on our consolidated financial statements. Adopted Standards Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable, and certain debt securities, with a current expected credit loss model (CECL). The CECL model is expected to result in more timely recognition of credit losses. The amendment was effective for reporting periods after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures. Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment was effective for reporting periods beginning after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures. |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer | REVENUE FROM CONTRACTS WITH CUSTOMERS Our revenue streams are reported under our three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 20 – Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. We sell the hydrocarbons (from the oil and natural gas and mid-stream segments) to other mid-stream and downstream oil and gas companies. We satisfy the performance obligation under each segment's contracts as follows: • contract drilling and mid-stream contracts - satisfy the performance obligations over the agreed-on time; • oil and natural gas contracts - satisfy the performance obligation with each volume delivery. For oil and natural gas contracts, as it is more feasible, we account for these deliveries monthly. Per the contracts for all segments, customers pay for the services/goods received monthly within an agreed number of days following the end of the month. Other than the mid-stream demand fees and shortfall fees discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting pronouncement. Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations Typical types of revenue contracts signed by our oil and gas segments are Oil Sales Contracts, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract terms can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues from our sales are recognized when our customer obtains control of the sold product. For sales we make to other mid-stream and downstream oil and gas companies, control typically occurs at a point on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard required no adjustment to opening retained earnings. Certain costs—as either a deduction from revenue or as an expense—are determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs are included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs. Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically, the contract is for a specified period (for example, a month or a year); however, each delivery under that contract can be considered as separately identifiable since each delivery provides its own benefits to the customer. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days following the end of the month of performance which includes payment for all deliveries in that month. Subject to any contract terms, judgment could be required to determine when the transfer of control occurs. Generally, depending on the facts and circumstances, we consider the change of control of the asset in a commodity sale to occur at the point the commodity transfers to the customer. The consideration we receive for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by a variable price less deductions related to any allowed gathering, transportation, fractionation, and related fuel charges. All variable consideration is settled at the end of the month; therefore, the variability does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. An estimation and allocation of transaction price and future obligations are not required. Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations The contract drilling segment uses contracts with terms ranging from two months to three Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on period as stated in the contract. Any mobilization and demobilization activities are not considered distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to three years. Most of the drilling contracts are for less than one year. As the customer simultaneously receives and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or by a set date. All consideration received for contract drilling is variable, excluding termination fees. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization, and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of December 31, 2020, we had nine drilling contracts (five of which are term contracts) for a duration of two months to one year. Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). Most of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts with a longer duration are not material. Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations Revenues are generated from the fees earned for gas gathering and processing services provided to a customer or by selling of hydrocarbons to other mid-stream companies. The typical revenue contracts used by this segment are gas gathering and processing agreements as well as product sales. Our gas gathering and processing revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received. Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees represent an arrangement where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized. Before implementing ASC 606, we immediately recognized the entire demand fee since the fee was payable within the first five years from the effective date of the contract and not over the entire term of the contract. However, the demand fee is a stand-ready obligation under ASC 606 and is now to be recognized over the life of the contract. Therefore, the demand fee previously recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018 and is recognized over the remaining term of the contract. Included below is the adjustment to demand fees from adopting ASC 606 over the remaining term of the contracts as of December 31, 2020. Contract Remaining Term of Contract 2021 2022 2023 and beyond Total Remaining Impact to Revenue Demand fee contracts 2-8 years $ (3,501) $ 1,380 $ 36 $ (2,085) The adjustment to revenue for these demand fees was $(3.8) million and $2.6 million in 2020 and 2019, respectively. Successor Predecessor Classification on the Consolidated Balance Sheets December 31, 2020 December 31, Change (In thousands) Assets Current contract assets Prepaid expenses and other $ 6,084 $ 6,664 $ (580) Non-current contract assets Other assets 173 6,257 (6,084) Total contract assets $ 6,257 $ 12,921 $ (6,664) Liabilities Current contract liabilities Current portion of other long-term liabilities $ 2,583 $ 2,889 $ (306) Non-current contract liabilities Other long-term liabilities 1,589 4,172 (2,583) Total contract liabilities 4,172 7,061 (2,889) Contract assets (liabilities), net $ 2,085 $ 5,860 $ (3,775) |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2019 | |
Acquisitions and Divestitures [Abstract] | |
Acquisitions and Divestitures | ACQUISITIONS AND DIVESTITURES Acquisitions Oil and Natural Gas During the Successor Period of 2020, there was no significant acquisition activity. During the Predecessor Period of 2020, we had $0.4 million in acquisitions, while for 2019, we had approximately $3.7 million in acquisitions. Mid-Stream There was no significant acquisition activity in 2020. In December 2019, we closed on an acquisition for $16.1 million that included approximately 572 miles of pipeline and related compressor stations. The transaction closed on December 30, 2019 with an effective date of December 01, 2019 and was accounted for as an asset acquisition. Divestitures Oil and Natural Gas We had non-core asset sales with proceeds, net of related expenses, of $0.4 million, $1.2 million and $21.8 million in the Successor Period and Predecessor Period of 2020 and the year 2019, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. Contract Drilling During 2019, we sold six of the drilling rigs and other equipment to unaffiliated third parties. The proceeds of those sales, less costs to sell, was more than the $5.7 million net book value resulting in a gain of $1.1 million. Seven drilling rigs and equipment remained classified as assets held for sale and were to be marketed for sale throughout the next twelve months. The net book value of those assets was $5.9 million. During the first quarter of 2020, due to market conditions, it was determined those assets would not be sold in the next twelve months and were reclassified to long-lived assets. As of December 31, 2020, we have no assets that meet the criteria to be classified as held for sale. We do have plans to sell drilling rigs but they have zero net book value after fresh start so they are not reported as assets held for sale. |
Earnings (Loss) Per Share
Earnings (Loss) Per Share | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share | LOSS PER SHARE Successor Period On the Effective Date, the company issued 12.0 million shares of New Common Stock at a par value of $0.01 per share that were to be subsequently distributed in accordance with the Plan. Information related to the calculation of loss per share attributable to the company is: Income (Loss) (Numerator) Weighted Per-Share (In thousands except per share amounts) For the four months ended December 31, 2020 Basic loss attributable to Unit Corporation per common share $ (18,140) 12,000 $ (1.51) Predecessor Period Information related to the calculation of loss per share attributable to the company is: Income (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the year ended December 31, 2019: Basic loss attributable to Unit Corporation per common share $ (553,879) 52,849 $ (10.48) Effect of dilutive stock options and restricted stock — — — Diluted loss attributable to Unit Corporation per common share $ (553,879) 52,849 $ (10.48) For the eight months ended August 31, 2020 Basic loss attributable to Unit Corporation per common share $ (931,012) 53,368 $ (17.45) The following options were not included in the weighted shares above as their affect would be anti-dilutive to the computation of loss per share for the year ended December 31: 2019 Stock options 42,000 Average exercise price $ 48.56 |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Accrued Liabilities [Abstract] | |
Accrued Liabilities | ACCRUED LIABILITIES Accrued liabilities consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) Employee costs $ 8,878 $ 17,832 Lease operating expenses 6,405 9,200 Taxes 2,324 3,450 Legal settlement (Note 18) 2,070 — Interest payable 884 6,562 Third-party credits — 3,691 Other 1,182 5,827 Total accrued liabilities $ 21,743 $ 46,562 |
Long-Term Debt And Other Long-T
Long-Term Debt And Other Long-Term Liabilities | 12 Months Ended |
Dec. 31, 2020 | |
Long-term debt and other long-term liabilites [Abstract] | |
Long-term Debt | LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES Long-Term Debt Long-term debt consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) Current portion of long-term debt: Predecessor credit facility with an average interest rate of 4.0% $ — $ 108,200 Successor Exit Facility with an average interest rate of 6.6% 600 — Long-term debt: Successor Exit Facility with an average interest of 6.6% 98,400 — Superior credit agreement with an average interest rate of 3.9% at December 31, 2019 — 16,500 Predecessor 6.625% senior subordinated notes due 2021 — 650,000 Total principal amount $ 98,400 $ 666,500 Less: unamortized discount — (971) Less: debt issuance costs, net — (2,313) Total long-term debt $ 98,400 $ 663,216 Successor Exit Credit Agreement. On the Effective Date, under the Plan, we entered into the Exit Credit Agreement, providing for a $140.0 million senior secured revolving credit facility and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC, (ii) the guarantors, including the company and all its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders under the agreement, and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (the Administrative Agent). The maturity date of borrowings under the Exit Credit Agreement is March 1, 2024. Revolving Loans and Term Loans (each as defined in the Exit Credit Agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit Credit Agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit Credit Agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit Credit Agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points. The Exit Credit Agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit Credit Agreement) as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ending December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit Credit Agreement) as of the last day of any fiscal quarter to be less than 0.50 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit Credit Agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit Credit Agreement also contains provisions, among others, that limit certain capital expenditures, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit Credit Agreement further requires that we provide quarterly financial statements within 45 days after the end of each of the first three quarters of each fiscal year and annual financial statements within 90 days after the end of each fiscal year. As of December 31, 2020, we were in compliance with these covenants. The Exit Credit Agreement is secured by first-priority liens on substantially all the personal and real property assets of the borrowers and the guarantors, including our ownership interests in Superior Pipeline Company, L.L.C. On the Effective Date, we had (i) $40.0 million in principal amount of Term Loans outstanding, (ii) $92.0 million in principal amount of Revolving Loans outstanding, and (iii) approximately $6.7 million of outstanding letters of credit. At December 31, 2020, we had $0.6 million and $98.4 million outstanding current and long-term borrowings, respectively, under the Exit Credit Agreement. Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit agreement had a scheduled maturity date of October 18, 2023 that would have accelerated to November 16, 2020 if, by that date, all the Notes were not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Chapter 11 Cases constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition, our debt associated with the Unit credit agreement is reflected as a current liability in our Consolidated Balance Sheets as of December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition was based on the uncertainty regarding our ability to repay or refinance the Notes before November 16, 2020. In addition, on May 22, 2020, the lenders' remaining commitments under the Unit credit agreement were terminated. Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees were being amortized over the life of the Unit credit agreement. Due to the remaining commitments under the Unit credit agreement being terminated by the lenders', the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020. Under the Unit credit agreement, we pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering those oil and gas properties, UPC also pledged certain items of its personal property. Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and was payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Predecessor credit agreement and the sum of the Federal Funds Effective Rate (as defined in the Unit credit agreement) plus 0.50%, but in no event would the interest on those borrowings be less than LIBOR plus 1.00% plus a margin. Interest was payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty. Filing the bankruptcy petitions on May 22, 2020 constituted an event of default that accelerated our obligations under the Unit credit agreement, and the lenders’ rights of enforcement under the Unit credit agreement were automatically stayed because of the Chapter 11 Cases. On the Effective Date, each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Credit Agreement, in exchange for that lender’s allowed claims under the Unit credit agreement or the DIP Credit Agreement. Superior Credit Agreement. On May 10, 2018, Superior entered into a five Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement. The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of December 31, 2020, Superior was in compliance with these covenants. Borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior. Unit is not a party to and does not guarantee Superior's credit agreement. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Superior credit agreement was not affected by Unit's bankruptcy. Predecessor 6.625% Senior Subordinated Notes. The Notes were issued under an Indenture dated as of May 18, 2011, between the company and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. As a result of Unit's emergence from bankruptcy, the Notes were cancelled and our liability under the Notes was discharged as of the Effective Date. Holders of the Notes were issued shares of New Common Stock in accordance with the Plan. Predecessor DIP Credit Agreement . As contemplated by the Restructuring Support Agreement between the company and certain of the Note holders and our lenders, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit agreement), among the Debtors, the lenders under the facility (the DIP lenders), and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP lenders agreed to provide us with the $36.0 million multiple-draw loan facility (DIP credit facility). The bankruptcy court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the bankruptcy court granted final approval of the DIP credit facility. Before its repayment and termination on the Effective Date, borrowings under the DIP credit facility matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP Credit Agreement and the bankruptcy court’s orders. On the Effective Date, the DIP credit facility was paid in full and terminated. On the Effective Date, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the Exit Credit Agreement. In addition, each holder was issued its pro rata share of an equity fee under the Exit Credit Agreement equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants). For further information about the DIP Credit Agreement, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11. Other Long-Term Liabilities Other long-term liabilities consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) ARO liability $ 23,356 $ 66,627 Workers’ compensation 10,164 11,510 Separation benefit plans (1) 4,201 10,122 Contract liability 4,172 7,061 Gas balancing liability 3,997 3,838 Finance lease obligations 3,216 7,379 Other long-term liability 1,321 — Deferred compensation plan — 6,180 50,427 112,717 Less current portion 11,168 17,376 Total other long-term liabilities $ 39,259 $ 95,341 _______________________ |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONSWe are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets (AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to plugging costs associated with our oil and gas wells. The following table shows certain information about our estimated AROs for the periods indicated (in thousands): ARO liability, December 31, 2019 (Predecessor) 66,627 Accretion of discount 1,545 Liability incurred 465 Liability settled (838) Liability sold (487) Revision of estimates (1) (28,328) ARO liability, August 31, 2020 (Predecessor) 38,984 Fresh start adjustments (14,393) ARO liability, August 31, 2020 (Successor) 24,591 Accretion of discount 467 Liability incurred 151 Liability settled (95) Liability sold — Revision of estimates (1) (1,758) ARO liability, December 31, 2020 (Successor) 23,356 Less current portion (Successor) 2,121 Total long-term ARO (Successor) $ 21,235 _______________________ |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES As previously stated, we filed for Chapter 11 Bankruptcy protection during the second quarter of 2020 and emerged from the cases in the third quarter of 2020. This event had a significant impact on income taxes during 2020. Under the Plan, the Company's pre-petition debt securities were extinguished and holders of those securities received their pro-rata share of New Common Stock. Holders of Old Common Stock that did not opt out of the release under the Plan received its pro-rata share of Warrants. Please refer to Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 for more information. As a result of the Plan, the company experienced an ownership change under Sec. 382 of the Internal Revenue Code (IRC). Under IRC Sec. 382, the company’s tax attributes, most notably its net operating loss carryovers, are potentially subject to various limitations going forward. The company believes it has satisfied the requirements of Sec. 382(l)(5) whereby our tax attributes are generally not subject to limitations under Sec. 382(a) and have reflected that result in our financials accordingly. While cancellation of debt income (CODI) is generally considered taxable income under IRC Sec. 108, it provides an exception to that rule for CODI realized under a Title 11 case of the United States Code. In exchange for this exception, the taxpayer must reduce certain tax attributes including its net operating loss carryovers, credit carryovers, and tax basis in its assets in the amount of the CODI not recognized under the IRC Sec. 108 exception. The amount of CODI not recognized as a result of the IRC Sec. 108 exception was $506.3 million. As a result, our net operating loss carryovers were reduced by $457.5 million and the tax basis of our assets were reduced by $48.8 million. Even though these tax attribute reductions are not effective until January 1, 2021, the first day of the tax year after emergence, they have been recognized and reflected as such in the tables below. A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows: Successor Predecessor Period Period For the Year Ended (In thousands) Income tax benefit computed by applying the statutory rate $ (3,001) $ (190,103) $ (144,092) State income tax benefit, net of federal benefit (500) (31,684) (21,733) Deferred tax liability revaluation — — — Restricted stock shortfall — 7,404 347 Non-controlling interest in Superior (1,017) 7,504 (11) Goodwill impairment — — 12,346 Valuation allowance 4,047 177,284 19,654 Reorganization adjustments — 14,152 — Statutory depletion and other 169 813 1,163 Income tax benefit $ (302) $ (14,630) $ (132,326) For the periods indicated, the total provision for income taxes consisted of the following: Successor Predecessor Period Period For the Year Ended (In thousands) Current taxes: Federal $ — $ (917) $ (918) State (302) — (363) (302) (917) (1,281) Deferred taxes: Federal — (16,663) (108,440) State — 2,950 (22,605) — (13,713) (131,045) Total provision $ (302) $ (14,630) $ (132,326) Deferred tax assets and liabilities are comprised of the following at December 31: Successor Predecessor 2020 2019 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 22,051 $ 31,822 Net operating loss carryforward 100,236 246,927 Depreciation, depletion, amortization, and impairment 80,947 — Alternative minimum tax and research and development tax credit carryforward 1,738 2,656 204,972 281,405 Deferred tax liability: Depreciation, depletion, amortization, and impairment — (226,034) Investment in Superior (3,987) (49,430) Net deferred tax asset (liability) 200,985 5,941 Valuation allowance (200,985) (19,654) Non-current—deferred tax liability $ — $ (13,713) A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the Consolidated Statements of Operations. During the year ended December 31, 2019, in evaluating whether it was more likely than not that the company's deferred tax assets were realizable through future net income, we considered all available positive and negative evidence, including (i) our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) our ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) future revenue and operating cost projections that indicate the company will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, we determined it was more likely than not that the deferred tax asset for net operating loss carryforwards were not fully realizable. As of December 31, 2019, a total valuation allowance of $19.7 million has been recorded. As of December 31, 2020, the valuation allowance had increased to $201.0 million to reflect a full valuation allowance against our net deferred tax assets due to the impacts of the Plan from our bankruptcy proceedings, fresh start accounting, and tax attribute reductions as prescribed by IRC Section 108. We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal tax examinations for years before 2016 or state income tax examinations by state taxing authorities for years before 2015. At December 31, 2020, we had expected federal net operating loss carryforwards of approximately $409.1 million of which $223.0 million would expire from 2021 to 2037. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2020 | |
Employee benefit plans [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis with cash or common stock. We made discretionary contributions under the plan of 310,797 shares of common stock in 2019 for the plan year 2018. The 2019 plan year matching contribution was made in cash instead of shares of common stock. On the Effective Date, all the shares of old common stock under the 401(k) Employee Thrift Plan were cancelled and each holder that did not opt out of the release under the Plan was entitled to receive his or her pro rata share of the Warrants in accordance with the Plan. Total 401(k) employer matching expense was $0.7 million, $1.4 million, and $5.2 million in the Successor Period of 2020, the Predecessor Period of 2020, and the year 2019, respectively. We provided a salary deferral plan for our executives (Deferral Plan) which allowed participants to defer the recognition of salary for income tax purposes until actual distribution of benefits occurred at either termination of employment, death, or certain defined unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2019 was $6.2 million. We recognized payroll expense and recorded a liability at the time of deferral. As of December 31, 2020, investments held in the Deferral Plan had been paid out to plan participants and the plan was terminated. As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides eligible employees with two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay. These benefits vest after 20 years of service provided to the company. We recognized expense of $1.4 million. $18.1 million, and $3.8 million in the Successor Period of 2020, the Predecessor Period of 2020, and the year 2019, respectively, for benefits associated with anticipated payments from these separation plans. |
Transactions With Related Parti
Transactions With Related Parties | 12 Months Ended |
Dec. 31, 2020 | |
Related Party Transactions [Abstract] | |
Transactions With Related Parties | TRANSACTIONS WITH RELATED PARTIESUnit Petroleum Company served as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.One former director, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in several states. The company in the ordinary course of business, paid royalties, or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, sometimes, as lessee, regarding certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.2 million and $0.4 million during the Predecessor period ended August 31, 2020 and the year ended December 31, 2019, respectively. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Stock-Based Compensation | STOCK-BASED COMPENSATION On the Effective Date, the Board adopted the Unit Corporation Long Term Incentive Plan (LTIP) to incentivize employees, officers, directors and other service providers of the company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, performance awards, substitute awards or any combination of the foregoing. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, 903,226 shares of new common stock of the reorganized company (New Common Stock) have been reserved for issuance pursuant to awards under the LTIP. New Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash, or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. The LTIP will be administered by the Board or a committee thereof. No shares under the LTIP have been awarded since the Effective Date through December 31, 2020. Also on the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. Under the Plan, the company issued Warrants to holders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the Plan. For further information, see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11. For restricted stock awards, we had: Predecessor Period For the Year Ended (In millions) Recognized stock compensation expense (1) $ 6.1 $ 12.8 Capitalized stock compensation cost for our oil and natural gas properties $ — $ 2.4 Tax benefit on stock-based compensation $ 1.5 $ 3.1 _______________________ 1. When the company's equity-based awards were cancelled on the Effective Date, we immediately recognized the expense for the cancelled awards of $1.4 million as reorganization costs, net. The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allowed us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. There were 7,230,000 shares of the company's common stock authorized for issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that could be issued as “incentive stock options.” The amended plan was terminated under the Plan. Restricted Stock Activity pertaining to restricted stock awards granted under the amended plan is as follows: Employees Number of Time Vested Shares Number of Performance Vested Shares Total Number of Shares Weighted Average Price Nonvested at January 1, 2019 (Predecessor) 1,268,883 608,125 1,877,008 $ 19.70 Granted 927,173 500,256 1,427,429 16.09 Vested (570,107) (233,835) (803,942) 15.56 Forfeited (98,301) (33,172) (131,473) 19.36 Nonvested at December 31, 2019 (Predecessor) 1,527,648 841,374 2,369,022 $ 18.95 Granted — — — — Vested (677,076) — (677,076) 19.95 Forfeited (272,396) (503,809) (776,205) 19.28 Nonvested at August 31, 2020 (Predecessor) 578,176 337,565 915,741 $ 17.92 Cancelled (578,176) (337,565) (915,741) 17.92 Nonvested at September 1, 2020 (Successor) — — — $ — Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2019 (Predecessor) 107,045 $ 17.07 Granted 72,784 12.09 Vested (61,141) 15.49 Forfeited — — Nonvested at December 31, 2019 (Predecessor) 118,688 $ 14.83 Granted — — Vested (48,475) 15.88 Forfeited — — Nonvested at August 31, 2020 (Predecessor) 70,213 $ 14.10 Cancelled (70,213) 14.10 Nonvested at September 1, 2020 (Successor) — $ — The time vested restricted stock awards granted were being recognized over a three The fair value of the restricted stock granted in 2019 at the grant date was $22.6 million. Non-Employee Directors' Stock Option Plan Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. These awards and the plan were cancelled on the Effective Date. Activity pertaining to the Directors’ Plan is as follows: Number of Shares Weighted Average Exercise Price Nonvested at January 1, 2019 (Predecessor) 66,500 $ 44.42 Granted — — Exercised — — Forfeited (24,500) 37.31 Nonvested at December 31, 2019 (Predecessor) 42,000 $ 48.56 Granted — — Exercised — — Forfeited (14,000) 41.21 Outstanding at August 31, 2020 (Predecessor) 28,000 $ 52.24 Cancelled (28,000) 52.24 Outstanding at September 1, 2020 (Successor) — $ — |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | DERIVATIVES Commodity Derivatives We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Exit Credit Agreement. For further details, see Note 9 – Long-Term Debt And Other Long-Term Liabilities. As of December 31, 2020, our derivative transactions consisted of the following types of hedges: • Basis/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points. • Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. • Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. We do not engage in derivative transactions for speculative purposes. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. At December 31, 2020, the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215) NGPL TEXOK Jan'21 - Oct'21 Natural gas - swap 50,000 MMBtu/day $2.818 IF - NYMEX (HH) Nov'21 - Dec'21 Natural gas - swap 45,000 MMBtu/day $2.900 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - swap 5,000 MMBtu/day $2.605 IF - NYMEX (HH) Jan'23 - Dec'23 Natural gas - swap 22,000 MMBtu/day $2.456 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - collar 35,000 MMBtu/day $2.50 - $2.68 IF - NYMEX (HH) Jan'21 - Dec'21 Crude oil - swap 3,000 Bbl/day $44.65 WTI - NYMEX Jan'22 - Dec'22 Crude oil - swap 2,300 Bbl/day $42.25 WTI - NYMEX Jan'23 - Dec'23 Crude oil - swap 1,300 Bbl/day $43.60 WTI - NYMEX The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31: Derivative Assets Fair Value Successor Predecessor Balance Sheet Location 2020 2019 (In thousands) Commodity derivatives: Current Current derivative assets $ — $ 633 Long-term Non-current derivative assets — — Total derivative assets $ — $ 633 Derivative Liabilities Fair Value Successor Predecessor Balance Sheet Location 2020 2019 (In thousands) Commodity derivatives: Current Current derivative liabilities $ 1,047 $ — Long-term Non-current derivative liabilities 4,659 27 Total derivative liabilities $ 5,706 $ 27 If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets. The following is the Effect of derivative instruments on the Consolidated Statements of Operations for the periods indicated: Derivatives Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative Successor Predecessor Period Period For the Year Ended (In thousands) Commodity derivatives Gain (loss) on derivatives, included are amounts settled during the period of $(1,133), $(4,244), and $16,196, respectively $ (985) $ (10,704) $ 4,225 Total $ (985) $ (10,704) $ 4,225 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows: • Level 1—unadjusted quoted prices in active markets for identical assets and liabilities. • Level 2—significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data. • Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data. The inputs available determine the valuation technique we use to measure the fair values presented in our financial instruments. The following tables set forth our recurring fair value measurements: Successor December 31, 2020 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 3,436 $ — $ (3,436) $ — Liabilities (9,142) — 3,436 (5,706) $ (5,706) $ — $ — $ (5,706) Predecessor December 31, 2019 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 177 $ 1,204 $ (748) $ 633 Liabilities (775) — 748 (27) $ (598) $ 1,204 $ — $ 606 All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2020. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities). Level 2 Fair Value Measurements Commodity Derivatives . We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index. Level 3 Fair Value Measurements Commodity Derivatives . The fair values of our natural gas and crude oil collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements. The following tables are reconciliations of our recurring level 3 fair value measurements: Net Derivatives Successor Predecessor Period Period For the Year Ended (In thousands) Beginning of period $ — $ 1,204 $ 10,630 Total gains or losses: Included in earnings — 978 (1,494) Settlements — (2,182) (7,932) End of period $ — $ — $ 1,204 Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ — $ (1,204) $ (9,426) Based on our valuation at December 31, 2020, we determined that the non-performance risk regarding our counterparties was immaterial. Fair Value of Other Financial Instruments We have determined the estimated fair values of other financial instruments by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. At December 31, 2020, the carrying values on the Consolidated Balance Sheets for cash, restricted cash, and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature. The Warrants are accounted for as a derivative liability as they are not indexed to the New Common Stock until all outstanding disputed claims against the company and UPC have been finally resolved and the strike price for the Warrants can be determined. Accordingly, the Warrants are recorded at their fair value using the Black-Scholes-Merton option model. The inputs to the model require various judgements, including estimating the strike price, expected term and the associated volatility. The Warrants are adjusted to fair value at each reporting period until determined to be an equity instrument, at which time they will be reported as shareholders' equity and no longer be subject to future fair value adjustment. At December 31, 2020, the Warrants have a fair value of $0.9 million. The Warrants are considered Level 3 fair value measurements . Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreements at December 31, 2020 would approximate its fair value. This debt is classified as Level 2. The carrying amount of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Consolidated Balance Sheets at December 31, 2019 was $646.7 million. On the Effective Date, our obligations with respect to the Notes were cancelled and holders of the Notes subsequently received their agreed on pro-rata share of New Common Stock. For further information, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11. The estimated fair value of these Notes using quoted market prices at December 31, 2019 was $357.5 million. These Notes were classified as Level 2. Fair Value of Non-Financial Instruments The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the company’s AROs is presented in Note 10 – Asset Retirement Obligations. Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2020 and 2019, we recorded non-cash impairment charges discussed further in Note 4 – Summary Of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3. See Note 3 - Fresh Start Accounting for additional disclosures of non-recurring fair value measurements associated with the qualification of fresh start under ASC 852. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Leases | LEASES Operating Leases under ASC 842 Adoption of Accounting Standards Codification (ASC) Topic 842, “Leases." We adopted Topic 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are presented under ASC 840. We determine whether a contract is or contains a lease at inception of the contract based on whether an identified asset exists and whether we have the right to obtain substantially all the benefit of the assets and to control its use over the full term of the agreement. When available, we use the rate explicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable explicit rate. Therefore, we must estimate our incremental borrowing rate considering both the revolving credit rates and a credit notching approach to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees and no restrictions or covenants included in our lease agreements. Certain of our leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput or actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets. Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of our full cost pool. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments. Practical Expedients and Policies Elected. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allowed us to carry forward the historical lease classification; and the land easement expedient, which allowed us to apply the guidance prospectively at adoption for land easements on existing agreements. We applied the short-term policy election, which allowed us to exclude from recognition on the balance sheet leases with an initial term of 12 months or less. We considered quantitative and qualitative factors when determining the application of the practical expedient that allowed us not to separate lease and non-lease components and are accounting for the agreements as a single lease component. We routinely enter into related party agreements between our three segments. These agreements have been evaluated under the guidance of ASC 842. Our oil and natural gas segment may contract for the use of drilling equipment from our drilling segment. We have determined that the contracting of our drilling segment's drilling rigs will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract per the lessor practical expedient. Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents noncash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged. Lease Agreements. We lease certain office space, land, and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include options to purchase the leased property. The following table sets forth the maturity of our operating lease liabilities as of December 31, 2020: Amount (In thousands) Ending December 31, 2021 $ 4,232 2022 1,305 2023 96 2024 12 2025 12 2026 and beyond 63 Total future payments 5,720 Less: Interest 200 Present value of future minimum operating lease payments 5,520 Less: Current portion 4,075 Total long-term operating lease payments $ 1,445 Finance Leases under ASC 842 During 2014, our mid-stream segment entered into finance lease agreements for 20 compressors with initial terms of seven Future payments required under the finance leases at December 31, 2020 are as follows: Amount Ending December 31, (In thousands) 2021 $ 3,774 Total future payments 3,774 Less payments related to: Maintenance 525 Interest 33 Present value of future minimum payments 3,216 Less: Current portion 3,216 Total long-term finance lease payments $ — Information about our lease assets and liabilities included in our Consolidated Balance Sheets as of December 31, 2020 and 2019 are as follows: Successor Predecessor Classification on the Consolidated Balance Sheets December 31, December 31, (In thousands) Assets Operating right of use assets Right of use assets $ 5,592 $ 5,673 Finance right of use assets Property, plant, and equipment, net 7,281 17,396 Total right of use assets $ 12,873 $ 23,069 Liabilities Current liabilities: Operating lease liabilities Current operating lease liabilities $ 4,075 $ 3,430 Finance lease liabilities Current portion of other long-term liabilities 3,216 4,164 Non-current liabilities: Operating lease liabilities Operating lease liabilities 1,445 2,071 Finance lease liabilities Other long-term liabilities — 3,215 Total lease liabilities $ 8,736 $ 12,880 The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated: Successor Predecessor Period Period Year Ended December 31, 2019 (In thousands) Components of total lease cost: Amortization of finance leased assets $ 1,406 $ 2,757 $ 4,001 Interest on finance lease liabilities 54 165 382 Operating lease cost 1,331 3,604 4,034 Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of less than $0.2 million, $1.5 million, and $24.7 million, respectively 3,664 8,190 38,868 Variable lease cost 64 223 351 Total lease cost $ 6,519 $ 14,939 $ 47,636 The following table provides supplemental cash flow information related to leases for the periods indicated: Successor Predecessor Period Period Year Ended December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 1,489 $ 3,849 $ 4,034 Financing cash flows for finance leases 1,407 2,757 4,001 Lease liabilities recognized in exchange for new operating lease right of use assets — — 5 The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases at December 31, 2020: Weighted Average Remaining Lease Term Weighted Average Discount Rate (1) (In years) Operating leases 1.6 4.41% Finance leases 0.7 4.00% _______________________ 1. Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | COMMITMENTS AND CONTINGENCIES Commitments Our mid-stream segment has firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.4 million for the one year thereafter. During the second quarter of 2018, as part of the Superior transaction (see Note 19 – Variable Interest Entity Arrangements), we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. At December 31, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. Total spent towards the $150.0 million as of December 31, 2020 was $24.8 million. We do not anticipate meeting the contractual obligation over the remaining commitment period. Environmental We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. We have not historically experienced any significant environmental liabilities while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. Litigation The company is subject to litigation and claims arising in the ordinary course of business which may include environmental, health and safety matters, or more routine employment related claims. The company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As new information becomes available or because of legal or administrative rulings in similar matters or a change in applicable law, the company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. Although we are insured against various risks, there is no assurance that the nature and amount of that insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. On May 22, 2020, the Debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). The Debtors emerged from the Chapter 11 Cases on the Effective Date. On the Effective Date, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan. For further information on the Chapter 11 Cases, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11. In 2013, the company’s exploration and production subsidiary, Unit Petroleum Company (UPC), drilled a well in Beaver County, Oklahoma. Certain operational issues arose and one of the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of the working interest owner, awarding $2.4 million in damages, including pre- and post-judgment interest. UPC appealed the verdict, and it was pending review in the Oklahoma Court of Civil Appeals. In February 2021, UPC finalized a settlement agreement with the working interest owner for $2.1 million in damages. As of December 31, 2020, the company's total accrual for loss contingencies was $2.1 million. Below is a summary of two other lawsuits and the respective treatment of those cases in the Chapter 11 Cases. Cockerell Oil Properties, Ltd., v. Unit Petroleum Company , No. 16-cv-135-JHP, United States District Court for the Eastern District of Oklahoma. On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that UPC wrongfully failed to pay interest with respect to late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells. Chieftain Royalty Company v. Unit Petroleum Company , No. CJ-16-230, District Court of LeFlore County, Oklahoma. On November 3, 2016, a putative class action lawsuit was filed against UPC styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that UPC breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells. Pending Settlement In August 2020, UPC reached an agreement to settle these class actions. Under the settlement, UPC agreed to recognize class proofs of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. This settlement is subject to certain conditions, including approval by the United States Bankruptcy Court for the Southern District of Texas, Houston Division in Case No. 20-32740 under the caption In re Unit Corporation, et al. Under the Plan, these settlement amounts will be treated as allowed general unsecured claims against UPC. The settlement amounts will be satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock in accordance with the Plan. Subsequent Event: Winter Storm In February of 2021, a severe winter storm impacted many of our operating areas in Oklahoma, Texas, and Kansas, resulting in certain disruptions to our operations. Although some uncertainties remain as to the ultimate impact and severity of these disruptions, we do not believe any such matters will have a material impact on our financial position. |
Variable Interest Entity Arrang
Variable Interest Entity Arrangements | 12 Months Ended |
Dec. 31, 2020 | |
Variable Interest Entity Arrangements [Abstract] | |
Variable Interest Entity Disclosure | VARIABLE INTEREST ENTITY ARRANGEMENTS On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and the MSA. The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator) and Superior. As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $260,560. Superior's creditors have no recourse to our general credit. Unit does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from available cash or made in conjunction with a sale event (both as defined in the Agreement). In certain circumstances, future distributions could result in Unit receiving distributions that are disproportionately lower than its ownership percentage. Circumstances that could result in Unit receiving less than a proportionate share of future distributions include, but may not be limited to, Unit not fulfilling the drilling commitment described in Note 18 – Commitments and Contingencies or a cumulative return to SP Investor Holdings, LLC of less than the 7% Liquidation IRR Hurdle provided for SP Investor Holdings, LLC in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor Holdings, LLC in excess of its original $300.0 million investment sufficient to provide SP Investor Holdings, LLC a 7% IRR on its capital contributions to Superior before any liquidation distribution is made to Unit. After the fifth anniversary of the effective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets. Effective at emergence, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our Consolidated Statements of Operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements. Under the guidance in ASC 810, Consolidation , we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA gives us the power to direct the activities that most significantly affect Superior's operating performance. The MSA is a separate variable interest. Under the MSA, Unit has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary as of December 31, 2020. As the primary beneficiary of this VIE, we consolidate in the financial statements the financial position, results of operations and cash flows of this VIE. All intercompany balances and transactions between us and the VIE are eliminated in the consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements. With consolidation of the VIE, the assets and liabilities of Superior were subject to fair value adjustments in accordance with ASC 852, Reorganizations. Therefore, the periods presented below are not comparative. The assets and liabilities of Superior at December 31, 2020 include the company’s application of fresh start accounting as described in Note 3 - Fresh Start Accounting, while the asset and liabilities at December 31, 2019, reflect historical basis, prior to any fresh start accounting adjustments. The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the Consolidated Balance Sheets. December 31, December 31, (In thousands) Current assets: Cash and cash equivalents $ 11,642 $ — Accounts receivable 27,427 21,073 Prepaid expenses and other 6,746 7,686 Total current assets 45,815 28,759 Property and equipment: Gas gathering and processing equipment 251,403 824,699 Transportation equipment 1,748 3,390 253,151 828,089 Less accumulated depreciation, depletion, amortization, and impairment 10,466 407,144 Net property and equipment 242,685 420,945 Right of use assets 2,823 3,948 Other assets 2,309 9,442 Total assets $ 293,632 $ 463,094 Current liabilities: Accounts payable $ 17,045 $ 18,511 Accrued liabilities 3,777 4,198 Current operating lease liability 1,762 2,407 Current portion of other long-term liabilities 5,799 7,060 Total current liabilities 28,383 32,176 Long-term debt less debt issuance costs — 16,500 Operating lease liability 1,013 1,404 Other long-term liabilities 1,589 8,126 Total liabilities $ 30,985 $ 58,206 |
Industry Segment Information
Industry Segment Information | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Industry Segment Information | INDUSTRY SEGMENT INFORMATION We have three main business segments offering different products and services: • Oil and natural gas, • Contract drilling, and • Mid-stream The oil and natural gas segment is engaged in the development, acquisition, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs. We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. The following table provides certain information about the operations of each of our segments: Successor Four Months Ended December 31, 2020 Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated (In thousands) Revenues: (1) Oil and natural gas $ 57,580 $ — $ — $ — $ (2) $ 57,578 Contract drilling — 19,413 — — — 19,413 Gas gathering and processing — — 68,369 — (11,832) 56,537 Total revenues 57,580 19,413 68,369 — (11,834) 133,528 Expenses: Operating costs: Oil and natural gas 26,111 — — — (855) 25,256 Contract drilling — 13,852 — — — 13,852 Gas gathering and processing — — 53,147 — (10,978) 42,169 Total operating costs 26,111 13,852 53,147 — (11,833) 81,277 Depreciation, depletion, and amortization 14,869 2,102 10,659 332 — 27,962 Impairments (2) 26,063 — — — — 26,063 Total expenses 67,043 15,954 63,806 332 (11,833) 135,302 General and administrative — — — 6,702 — 6,702 Gain on disposition of assets (24) (521) (55) (19) — (619) Income (loss) from operations (9,439) 3,980 4,618 (7,015) (1) (7,857) Loss on derivatives — — — (985) — (985) Reorganization items, net — — — (2,273) — (2,273) Interest, net — — (501) (2,774) — (3,275) Other 56 4 34 6 — 100 Income (loss) before income taxes $ (9,383) $ 3,984 $ 4,151 $ (13,041) $ (1) $ (14,290) Identifiable assets: Oil and natural gas (3) $ 236,073 $ — $ — $ — $ (3,326) $ 232,747 Contract drilling — 81,612 — — (4) 81,608 Gas gathering and processing — — 293,632 — (335) 293,297 Total identifiable assets (4) 236,073 81,612 293,632 — (3,665) 607,652 Corporate land and building — — — 32,382 — 32,382 Other corporate assets (5) — — — 13,671 (4,002) 9,669 Total assets $ 236,073 $ 81,612 $ 293,632 $ 46,053 $ (7,667) $ 649,703 Capital expenditures: $ 4,018 $ 616 $ 1,323 $ 3 $ — $ 5,960 _______________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax. 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Predecessor Eight Months Ended August 31, 2020 Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 103,443 $ — $ — $ — $ (4) $ 103,439 Contract drilling — 73,519 — — — 73,519 Gas gathering and processing — — 114,531 — (14,532) 99,999 Total revenues (1) 103,443 73,519 114,531 — (14,536) 276,957 Expenses: Operating costs: Oil and natural gas 119,664 — — — (1,973) 117,691 Contract drilling — 51,811 — — (1) 51,810 Gas gathering and processing — — 80,607 — (12,562) 68,045 Total operating costs 119,664 51,811 80,607 — (14,536) 237,546 Depreciation, depletion, and amortization 68,762 15,544 29,371 1,819 — 115,496 Impairments (2) 393,726 410,126 63,962 — — 867,814 Total expenses 582,152 477,481 173,940 1,819 (14,536) 1,220,856 Loss on abandonment of assets 17,641 1,092 — — — 18,733 General and administrative — — — 42,766 — 42,766 (Gain) loss on disposition of assets (160) (1,390) (18) 1,479 — (89) Loss from operations (496,190) (403,664) (59,391) (46,064) — (1,005,309) Loss on derivatives — — — (10,704) — (10,704) Write-off of debt issuance costs — — — (2,426) — (2,426) Reorganization items, net 15,504 (183,664) (71,016) 373,151 — 133,975 Interest, net — — (1,888) (20,936) — (22,824) Other 458 1,449 50 77 — 2,034 Income (loss) before income taxes $ (480,228) $ (585,879) $ (132,245) $ 293,098 $ — $ (905,254) Capital expenditures: $ 5,350 $ 2,438 $ 9,342 $ 83 $ — $ 17,213 _______________________ ____________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. Predecessor Year Ended December 31, 2019 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 325,797 $ — $ — $ — $ — $ 325,797 Contract drilling — 184,192 — — (15,809) 168,383 Gas gathering and processing — — 227,939 — (47,485) 180,454 Total revenues (1) 325,797 184,192 227,939 — (63,294) 674,634 Expenses: Operating costs: Oil and natural gas 140,026 — — — (4,902) 135,124 Contract drilling — 130,188 — — (14,190) 115,998 Gas gathering and processing — — 176,189 — (42,583) 133,606 Total operating costs 140,026 130,188 176,189 — (61,675) 384,728 Depreciation, depletion, and amortization 168,651 51,552 47,663 7,707 — 275,573 Impairments (2) 559,867 62,809 3,040 — — 625,716 Total expenses 868,544 244,549 226,892 7,707 (61,675) 1,286,017 General and administrative — — — 38,246 — 38,246 (Gain) loss on disposition of assets (199) 3,872 (160) (11) — 3,502 Income (loss) from operations (542,548) (64,229) 1,207 (45,942) (1,619) (653,131) Gain on derivatives — — — 4,225 — 4,225 Interest expense, net — — (1,546) (35,466) — (37,012) Other (481) (605) 827 23 — (236) Income (loss) before income taxes $ (543,029) $ (64,834) $ 488 $ (77,160) $ (1,619) $ (686,154) Identifiable assets: Oil and natural gas (3) 851,662 — — — (4,264) 847,398 Contract drilling — 708,510 — — (42) 708,468 Gas gathering and processing — — 463,699 — (4,255) 459,444 Total identifiable assets (4) 851,662 708,510 463,699 — (8,561) 2,015,310 Corporate land and building — — — 54,155 — 54,155 Other corporate assets (5) — — — 23,092 (2,505) 20,587 Total assets $ 851,662 $ 708,510 $ 463,699 $ 77,247 $ (11,066) $ 2,090,052 Capital expenditures: $ 268,622 $ 40,636 $ 64,438 $ 673 $ — $ 374,369 _______________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
Selected Quarterly Financial In
Selected Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2020 | |
Selected Quarterly Financial Information [Abstract] | |
Selected Quarterly Financial Information | SELECTED QUARTERLY FINANCIAL INFORMATION Summarized unaudited quarterly financial information is as follows: First Second Third Quarter (1) Fourth (In thousands except per share amounts) 2020 (Successor) Revenues $ — $ — $ 32,846 $ 100,682 Gross income (loss) (2) $ — $ — $ (7,373) $ 5,599 Net loss attributable to Unit Corporation $ — $ — $ (8,968) (3) $ (9,172) (4) Net loss attributable to Unit Corporation per common share: Basic $ — $ — $ (0.75) $ (0.76) Diluted $ — $ — $ (0.75) $ (0.76) 2020 (Predecessor) Revenues $ 122,376 $ 89,007 $ 65,574 $ — Gross loss (2) $ (764,888) $ (171,374) $ (7,637) $ — Net income (loss) attributable to Unit Corporation $ (770,494) (5) $ (215,649) (6) $ 55,131 (7) $ — Net income (loss) attributable to Unit Corporation per common share: Basic $ (14.50) $ (4.03) $ 1.03 $ — Diluted $ (14.50) $ (4.03) $ 1.03 $ — 2019 (Predecessor) Revenues $ 189,691 $ 165,146 $ 155,439 $ 164,358 Gross income (loss) (2) $ 24,095 $ 813 $ (242,308) $ (393,983) Net loss attributable to Unit Corporation $ (3,504) $ (8,509) $ (206,886) (8) $ (334,980) (9) Net loss attributable to Unit Corporation per common share: Basic $ (0.07) $ (0.16) $ (3.91) $ (6.33) Diluted $ (0.07) $ (0.16) $ (3.91) $ (6.33) _________________________ 1. Third quarter for the 2020 Predecessor Period is for the period July 1, 2020 through August 31, 2020. Third quarter for the 2020 Successor Period is the period September 1, 2020 through September 30, 2020. 2. Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, loss on abandonment of assets, gain (loss) on derivatives, reorganization items, net, income taxes, and other income (loss). 3. During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. 4. During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax. 5. During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets. 6. During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax. 7. During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net. 8. During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax). 9. During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax). |
Supplemental Condensed Consolid
Supplemental Condensed Consolidated Financial Information | 12 Months Ended |
Dec. 31, 2020 | |
Condensed Financial Information Disclosure [Abstract] | |
Supplemental Condensed Consolidating Financial Information | SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION The Notes of the Predecessor company were registered securities until they were cancelled on the Effective Date. As a result, we are required to present the following condensed consolidating financial information for the Predecessor Periods under to Rule 3-10 of the SEC's Regulation S-X, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered. Our Successor Exit Credit Agreement is not a registered security. Therefore, the presentation of condensed consolidating financial information is not required for the Successor Period. For the following footnote: • we were called "Parent", • the direct subsidiaries were 100% owned by the Parent and the guarantee was full, unconditional, and joint and several and called "Combined Guarantor Subsidiaries", and • Superior and its subsidiaries and the Operator were called "Non-Guarantor Subsidiaries." The following supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated. Condensed Consolidating Balances Sheets Predecessor December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 503 $ 68 $ — $ — $ 571 Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216) 2,645 64,805 24,653 (9,447) 82,656 Materials and supplies — 449 — — 449 Current derivative asset 633 — — — 633 Income tax receivable 1,756 — — — 1,756 Assets held for sale — 5,908 — — 5,908 Prepaid expenses and other 2,019 3,373 7,686 — 13,078 Total current assets 7,556 74,603 32,339 (9,447) 105,051 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 6,341,582 — — 6,341,582 Unproved properties not being amortized — 252,874 — — 252,874 Drilling equipment — 1,295,713 — — 1,295,713 Gas gathering and processing equipment — — 824,699 — 824,699 Saltwater disposal systems — 69,692 — — 69,692 Corporate land and building — 59,080 — — 59,080 Transportation equipment 9,712 16,621 3,390 — 29,723 Other 28,927 29,065 — — 57,992 38,639 8,064,627 828,089 — 8,931,355 Less accumulated depreciation, depletion, amortization, and impairment 33,794 6,537,731 407,144 — 6,978,669 Net property and equipment 4,845 1,526,896 420,945 — 1,952,686 Intercompany receivable 1,048,785 — — (1,048,785) — Investments 865,252 — — (865,252) — Right of use asset 46 1,733 3,948 (54) 5,673 Other assets 8,107 9,094 9,441 — 26,642 Total assets $ 1,934,591 $ 1,612,326 $ 466,673 $ (1,923,538) $ 2,090,052 Predecessor December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 12,259 $ 61,002 $ 18,511 $ (7,291) $ 84,481 Accrued liabilities 28,003 14,024 6,691 (2,156) 46,562 Current operating lease liability 20 1,009 2,407 (6) 3,430 Current portion of long-term debt 108,200 — — — 108,200 Current portion of other long-term liabilities 3,003 7,313 7,060 — 17,376 Total current liabilities 151,485 83,348 34,669 (9,453) 260,049 Intercompany debt — 1,047,599 1,186 (1,048,785) — Long-term debt less debt issuance costs 646,716 — 16,500 — 663,216 Non-current derivative liability 27 — — — 27 Operating lease liability 25 690 1,404 (48) 2,071 Other long-term liabilities 12,553 74,662 8,126 — 95,341 Deferred income taxes 68,150 (54,437) — — 13,713 Total shareholders' equity 1,055,635 460,464 404,788 (865,252) 1,055,635 Total liabilities and shareholders’ equity $ 1,934,591 $ 1,612,326 $ 466,673 $ (1,923,538) $ 2,090,052 Condensed Consolidating Statements of Operations Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 176,962 $ 114,531 $ (14,536) $ 276,957 Expenses: Operating costs — 171,476 80,607 (14,537) 237,546 Depreciation, depletion, and amortization 1,819 84,306 29,371 — 115,496 Impairments — 803,852 63,962 — 867,814 Loss on abandonment of assets — 18,733 — — 18,733 General and administrative — 42,766 — — 42,766 (Gain) loss on disposition of assets 1,479 (1,550) (18) — (89) Total operating costs 3,298 1,119,583 173,922 (14,537) 1,282,266 Income (loss) from operations (3,298) (942,621) (59,391) 1 (1,005,309) Interest, net (20,936) — (1,888) — (22,824) Write-off of debt issuance costs (2,426) — — — (2,426) Loss on derivatives (10,704) — — — (10,704) Reorganization items 373,151 (168,160) (71,016) — 133,975 Other, net 79 1,906 49 — 2,034 Income (loss) before income taxes 335,866 (1,108,875) (132,246) 1 (905,254) Income tax benefit (14,630) — — — (14,630) Equity in net earnings from investment in subsidiaries, net of taxes (1,241,120) — — 1,241,120 — Net loss (890,624) (1,108,875) (132,246) 1,241,121 (890,624) Less: net income attributable to non-controlling interest 40,388 — 40,388 (40,388) 40,388 Net loss attributable to Unit Corporation $ (931,012) $ (1,108,875) $ (172,634) $ 1,281,509 $ (931,012) Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 494,180 $ 227,939 $ (47,485) $ 674,634 Expenses: Operating costs — 256,024 176,189 (47,485) 384,728 Depreciation, depletion, and amortization 7,707 220,203 47,663 — 275,573 Impairments — 622,676 3,040 — 625,716 General and administrative — 38,246 — — 38,246 (Gain) loss on disposition of assets (11) 3,673 (160) — 3,502 Total operating costs 7,696 1,140,822 226,732 (47,485) 1,327,765 Income (loss) from operations (7,696) (646,642) 1,207 — (653,131) Interest, net (35,466) — (1,546) — (37,012) Gain on derivatives 4,225 — — — 4,225 Other, net 786 (1,086) 64 — (236) Loss before income taxes (38,151) (647,728) (275) — (686,154) Income tax expense (benefit) 7,238 (139,564) — — (132,326) Equity in net earnings from investment in subsidiaries, net of taxes (508,439) — — 508,439 — Net loss (553,828) (508,164) (275) 508,439 (553,828) Less: net income attributable to non-controlling interest 51 — 51 (51) 51 Net loss attributable to Unit Corporation $ (553,879) $ (508,164) $ (326) $ 508,490 $ (553,879) Condensed Consolidating Statements of Comprehensive Income (Loss) Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (890,624) $ (1,108,875) $ (132,246) $ 1,241,121 $ (890,624) Other comprehensive loss, net of taxes: Unrealized gain on securities, net of tax of $0 — — — — — Comprehensive loss (890,624) (1,108,875) (132,246) 1,241,121 (890,624) Less: Comprehensive income attributable to non-controlling interests 40,388 — 40,388 (40,388) 40,388 Comprehensive loss attributable to Unit Corporation $ (931,012) $ (1,108,875) $ (172,634) $ 1,281,509 $ (931,012) Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (553,828) $ (508,164) $ (275) $ 508,439 $ (553,828) Other comprehensive loss, net of taxes: Reclassification adjustment for write-down of securities, net of tax $(47) — 481 — — 481 Comprehensive loss (553,828) (507,683) (275) 508,439 (553,347) Less: Comprehensive income attributable to non-controlling interests 51 — 51 (51) 51 Comprehensive loss attributable to Unit Corporation $ (553,879) $ (507,683) $ (326) $ 508,490 $ (553,398) Condensed Consolidating Statements of Cash Flows Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (207,593) $ 82,769 $ 32,922 $ 136,858 $ 44,956 INVESTING ACTIVITIES: Capital expenditures (986) (14,585) (10,204) — (25,775) Producing properties and other acquisitions — (382) — — (382) Proceeds from disposition of assets 1,169 4,772 77 — 6,018 Net cash provided by (used in) investing activities 183 (10,195) (10,127) — (20,139) FINANCING ACTIVITIES: Borrowings under credit agreement, including borrowings under DIP credit facility 55,300 — 32,100 — 87,400 Payments under credit agreement (31,500) — (32,600) — (64,100) DIP financing costs (990) — — — (990) Exit facility financing costs (3,225) — — — (3,225) Intercompany borrowings (advances), net 210,398 (72,642) (898) (136,858) — Payments on finance leases — — (2,757) — (2,757) Employee taxes paid by withholding shares (43) — — — (43) Bank overdrafts (7,269) — (1,464) — (8,733) Net cash provided by (used in) financing activities 222,671 (72,642) (5,619) (136,858) 7,552 Net increase (decrease) in cash and cash equivalents 15,261 (68) 17,176 — 32,369 Cash and cash equivalents, beginning of period 503 68 — — 571 Cash and cash equivalents, end of period $ 15,764 $ — $ 17,176 $ — $ 32,940 Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (9,681) $ 217,883 $ 48,856 $ 12,338 $ 269,396 INVESTING ACTIVITIES: Capital expenditures 65 (355,258) (51,472) — (406,665) Producing properties and other acquisitions — (3,653) — — (3,653) Other acquisitions — — (16,109) — (16,109) Proceeds from disposition of assets 11 31,153 700 — 31,864 Net cash provided by (used in) investing activities 76 (327,758) (66,881) — (394,563) FINANCING ACTIVITIES: Borrowings under credit agreement 400,600 — 92,900 — 493,500 Payments under credit agreement (292,400) — (76,400) — (368,800) Intercompany borrowings (advances), net (97,455) 109,735 58 (12,338) — Payments on finance leases — — (4,001) — (4,001) Employee taxes paid by withholding shares (4,158) — — — (4,158) Distributions to non-controlling interest 919 — (1,837) — (918) Bank overdrafts 2,199 — 1,464 — 3,663 Net cash provided by (used in) financing activities 9,705 109,735 12,184 (12,338) 119,286 Net increase (decrease) in cash and cash equivalents 100 (140) (5,841) — (5,881) Cash and cash equivalents, beginning of period 403 208 5,841 — 6,452 Cash and cash equivalents, end of period $ 503 $ 68 $ — $ — $ 571 |
Supplemental Oil And Gas Disclo
Supplemental Oil And Gas Disclosures | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Oil and Gas Disclosures [Abstract] | |
Supplemental Oil And Gas Disclosures | SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED) The supplemental data presented herein reflects information for all our oil and natural gas producing activities. Our oil and gas operations are substantially located in the United States. Capitalized Costs The capitalized costs at year end were as follows: Successor Predecessor 2020 2019 (In thousands) Proved properties $ 238,581 $ 6,341,582 Unproved properties (wells in progress) 1,591 252,874 240,172 6,594,456 Accumulated depreciation, depletion, amortization, and impairment (40,806) (5,846,177) Net capitalized costs $ 199,366 $ 748,279 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities The following table sets forth costs incurred related to our oil and natural gas activities for the periods indicated: Successor Predecessor Period Period For the Year Ended (In thousands) Unproved properties acquired $ 26 $ 2,373 $ 34,668 Proved properties acquired — 382 3,653 Exploration — — 16,480 Development 3,992 6,440 211,443 Asset retirement obligation (1,702) (29,189) 76 Total costs incurred $ 2,316 $ (19,994) $ 266,320 Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation. The results of operations for producing activities are as follows: Successor Predecessor Period Period For the Year Ended (In thousands) Revenues $ 55,272 $ 96,033 $ 314,925 Production costs (20,510) (46,633) (116,051) Depreciation, depletion, amortization, and impairment (40,840) (461,901) (727,529) (6,078) (412,501) (528,655) Income tax (expense) benefit 128 6,698 101,952 Results of operations for producing activities (excluding corporate overhead and financing costs) $ (5,950) $ (405,803) $ (426,703) Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows: Oil Bbls NGLs Bbls Natural Gas Mcf Total MBoe (In thousands) 2019 Proved developed and undeveloped reserves: Beginning of year 22,558 47,796 535,963 159,681 Revision of previous estimates (1) (8,263) (20,961) (234,852) (68,366) Extensions and discoveries (1) 703 845 8,798 3,015 Infill reserves in existing proved fields 271 434 4,806 1,506 Purchases of minerals in place 183 101 1,316 503 Production (3,208) (4,773) (53,064) (16,825) Sales (48) (412) (42,780) (7,590) Net proved reserves at December 31, 2019 12,196 23,030 220,187 71,924 Proved developed reserves, December 31, 2019 12,196 23,030 220,187 71,924 Proved undeveloped reserves, December 31, 2019 — — — — 2020 Proved developed and undeveloped reserves: Beginning of year 12,196 23,030 220,187 71,924 Revision of previous estimates (1,909) (4,477) (38,901) (12,870) Extensions and discoveries 8 13 110 39 Infill reserves in existing proved fields 97 66 452 238 Purchases of minerals in place 62 20 172 112 Production (2,186) (3,444) (37,567) (11,891) Sales (1) — (62) (11) Net proved reserves at December 31, 2020 8,267 15,208 144,391 47,541 Proved developed reserves, December 31, 2020 8,267 15,208 144,391 47,541 Proved undeveloped reserves, December 31, 2020 — — — — _________________________ 1. Revisions of previous estimates and extensions and discoveries decreased primarily due to the removal of proved undeveloped reserves due to uncertainty regarding our ability to finance the development of our proved undeveloped reserves over a five-year period and from lower commodity prices. Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed, the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows. The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows: Successor Predecessor 2020 2019 (In thousands) Future cash flows $ 698,685 $ 1,386,777 Future production costs (416,095) (698,357) Future development costs — — Future income tax expenses (39) (321) Future net cash flows 282,551 688,099 10% annual discount for estimated timing of cash flows (89,530) (226,390) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 193,021 $ 461,709 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: 2020 2019 Sales and transfers of oil and natural gas produced, net of production costs $ (84,163) $ (200,233) Net changes in prices and production costs (165,978) (508,066) Revisions in quantity estimates and changes in production timing (50,979) (338,994) Extensions, discoveries, and improved recovery, less related costs 2,827 53,123 Changes in estimated future development costs — 311,190 Previously estimated cost incurred during the period — 64,362 Purchases of minerals in place 852 6,416 Sales of minerals in place (46) (25,813) Accretion of discount 46,203 110,571 Net change in income taxes 282 121,708 Changes in timing and other (17,686) (116,233) Net change (268,688) (521,969) Beginning of year 461,709 983,678 End of year $ 193,021 $ 461,709 Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized. The December 31, 2020, future cash flows were computed by applying the unescalated 12-month average prices of $39.57 per barrel for oil, $18.70 per barrel for NGLs, and $1.98 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves. Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur. |
Schedule II - Valuation And Qua
Schedule II - Valuation And Qualifying Accounts And Reserves | 12 Months Ended |
Dec. 31, 2020 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Valuation And Qualifying Accounts And Reserves | VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Allowance for Doubtful Accounts: Description Balance at Beginning of Period Additions Deductions & Net Write-Offs Balance at End of Period (In thousands) Year ended December 31, 2020 $ 2,332 $ 3,155 $ (1,704) $ 3,783 Year ended December 31, 2019 $ 2,531 $ 527 $ (726) $ 2,332 |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidate the activities of Superior, a 50/50 joint venture between Unit and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 19 – Variable Interest Entity Arrangements.Effective at emergence, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our Consolidated Statements of Operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements. |
Fresh start accounting policy | The consolidated financial statements in Note 3 - Fresh Start Accounting have been prepared in accordance with Financial Accounting Standard Board (FASB) ASC Topic 852, Reorganizations . We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting Date) would not have a material impact to the consolidated financial statements. This was reflected in our Consolidated Balance Sheets as of September 1, 2020. Accordingly, our consolidated financial statements and notes after September 1, 2020, are not comparable to the consolidated financial statements and notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor. |
Accounting Estimates | Preparing financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Drilling Contracts | Because we not do bear the risk of completion of the well, we recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed. Typically, this type of contract can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2020, all our contracts were daywork contracts of which five were multi-well and had durations which ranged from two months to one year, three of which expire in 2021 and two expiring in 2022. These longer-term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate. |
Cash Equivalents and Bank Overdrafts | We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Bank overdrafts are checks issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2020 and 2019, bank overdrafts were $2.6 million and $8.7 million, respectively. |
Accounts Receivable | Accounts receivable is carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful. |
Financial Instruments and Concentrations Of Credit Risk and Non-Performance Risk | Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to our receivables. Our credit risk is considered limited due to the many customers comprising our customer base. Below are the third-party customers that accounted for over 10% of each of our segment’s revenues: Successor Predecessor Period Period For the Year Ended Oil and Natural Gas: CVR Refining, LP 14 % 15 % 14 % Plains Marketing L.P. * 11 % * Drilling: EOG Resources, Inc. 28 % 20 % 12 % QEP Resources, Inc. 23 % 10 % 12 % Citizen Energy III, LLC 16 % * * Slawson Exploration Company, Inc. 16 % 21 % 11 % Cimarex Energy Co. 12 % * * Mid-Stream: ONEOK, Inc. 28 % 31 % 33 % Range Resources Corporation 15 % 21 % 13 % Centerpoint Energy Service, Inc. * * 10 % _______________________ * Revenue accounted for less than 10% of the segment's revenues. We had a concentration of cash of $21.4 million and $1.7 million at December 31, 2020 and 2019, respectively with one bank. Using derivative transactions also involves the risk that the counterparties cannot meet the financial terms of the transactions. We considered this non-performance risk regarding our counterparties and our own non-performance risk in our derivative valuation at December 31, 2020 and determined there was no material risk at that time. At December 31, 2020, the fair values of the net liabilities we had with each of the counterparties regarding our commodity derivative transactions are listed in the table below: December 31, 2020 (In millions) Bank of Oklahoma $ (5.4) Bank of Montreal (0.3) Total net liabilities $ (5.7) |
Property and Equipment | Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Prior to emergence from bankruptcy, we recorded depreciation of drilling equipment using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle, unless idle for greater than 48 months, then it was depreciated at the full active rate. We also used the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage drilled compared to total estimated remaining footage. As of emergence, we elected to depreciate all drilling assets utilizing the straight-line method over the useful lives of the assets ranging from four to ten years. Depreciation on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years. We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets. At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $407.1 million in the first quarter of 2020. We also recorded an additional non-cash impairment charge of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairment charge in our Consolidated Statements of Operations. We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management’s best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future. We concluded that no impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately $242.5 million at March 31, 2020. The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin, which means minor changes in certain key assumptions in future periods may result in material impairment charges in future periods. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values. We recorded expense of $1.1 million related to the write-down of certain equipment in the third quarter of 2020 that we now consider abandoned. These amounts are reported in loss on abandonment of assets in our Consolidated Statements of Operations. During the third quarter of 2019, we determined a triggering event had occurred within our contract drilling segment due to a decline in the number of drilling rigs being used and the overall market performance of the contract drilling industry. As a result, we performed a recoverability test on long-lived assets within that segment. Based on the results of the undiscounted future cash flows of that asset group, the undiscounted projected future cash flows of the asset group exceeded the group's carrying value as of September 30, 2019 and therefore no long-lived asset impairment was recorded for the group. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation. |
Capitalized Interest | During 2019, interest of approximately $16.2 million was capitalized based on the net book value associated with unproved oil and gas properties not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest in 2020. |
Goodwill | Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed annually to determine whether the fair value has decreased or additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, using discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. Due to the triggering event within the contract drilling segment, we performed an interim goodwill impairment test as of September 30, 2019. Based on the projected discounted cash flows, we recognized a goodwill impairment charge of $62.8 million, pre-tax ($59.8 million, net of tax) which represented total goodwill we previously reported on our Consolidated Balance Sheets. There were no additions to goodwill in 2020 or 2019. |
Oil and Natural Gas Operations | We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. All productive and non-productive costs incurred in connection with the acquisition, exploration, and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs. Directly related overhead costs of $16.5 million were capitalized in 2019. We did not capitalize any directly related overhead costs in 2020. Capitalized costs are amortized on a units-of-production method based on proved oil and natural gas reserves. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. The average rates used for DD&A were $4.21, $7.77, and $9.66 per Boe in the Successor Period of 2020, the Predecessor Period of 2020, and for the year 2019, respectively. During the fourth quarter 2019, we reassessed estimated salvage values associated with our oil and natural gas operations. Based on market conditions for our industry and the substantial doubt that existed for our ability to continue as a going concern, we revised these estimates downward for a total adjustment of $39.7 million ($25.6 million discounted for our full cost ceiling test) to salvage value estimates. No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties. Successor Period Impairments . As of September 1, 2020, we adopted fresh start accounting and adjusted our assets to fair value. Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in non-cash ceiling test write-downs of $26.1 million pre-tax for Successor Period primarily due to the use of average 12-month historical commodity prices for the ceiling test versus forward prices for our Fresh Start fair value estimates. It is hard to predict with any certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2020, and only adjust the 12-month average price as of March 2021, our forward-looking expectation is that we will not recognize an impairment in the first quarter of 2021. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination. Predecessor Period Impairments. We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $226.5 million and $73.9 million in 2020 and 2019, respectively, of costs being added to the total of our capitalized costs being amortized. We recorded non-cash ceiling test write-downs of $393.7 million pre-tax ($346.6 million, net of tax) in the Predecessor Period of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. We incurred non-cash ceiling test write-downs of $559.4 million pre-tax ($422.4 million, net of tax) in 2019. In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of the use of those assets, we determined that some of those assets were no longer expected to be used and we wrote off those salt water disposal assets that we now consider abandoned. We recorded total expense of $17.6 million related to the write-down of those salt water |
ARO | We record the fair value of liabilities associated with the future plugging and abandonment of our wells. When the reserves in each of our oil or gas wells becoming fully depleted or otherwise become uneconomical, we incur costs to plug and abandon the wells. These future costs are recorded at the time the wells are drilled or acquired. We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool. |
Insurance | We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums. |
Derivative Activities | All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. Cash settlements received or paid for matured, early-terminated, and modified derivatives are reported in cash receipts (payments) on derivatives settled in our Consolidated Statements of Cash Flows.We do not engage in derivative transactions solely for speculative purposes. |
Limited Partnerships | Unit Petroleum Company was a general partner in 13 oil and natural gas limited partnerships. Some of our officers, directors, and employees owned the interests in most of these partnerships. We shared in each partnership’s revenues and costs under formulas set out in the limited partnership agreement. The partnerships also reimbursed us for certain administrative costs incurred on behalf of the partnerships. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest. |
Income Taxes | Measurement of net deferred tax liabilities is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where needed to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities. The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. |
Natural Gas Balancing | We account for revenue transactions under ASC 606 for recording natural gas sales, which may be more or less than our share of pro-rata production from certain wells. We estimate our December 31, 2020 balancing position to be approximately 3.3 Bcf on under-produced properties and approximately 3.3 Bcf on over-produced properties. We have recorded a receivable of $3.4 million on certain wells where we estimate that insufficient reserves are available for us to recover our under-production from future production volumes. We have also recorded a liability of $4.0 million on certain properties where there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material. |
Employee And Director Stock Based Compensation | We recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. Our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We used the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants was based on the closing stock price on the date of the grants. On the Effective Date, all unvested restricted stock and un-exercised stock options were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. See Note 14 – Stock-Based Compensation for further detail. |
New Accounting Standards | Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The amendments will not have a material impact on our consolidated financial statements. Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments will be effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. This standard will not have a material impact on our consolidated financial statements. Adopted Standards Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable, and certain debt securities, with a current expected credit loss model (CECL). The CECL model is expected to result in more timely recognition of credit losses. The amendment was effective for reporting periods after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures. Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment was effective for reporting periods beginning after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures. |
Fresh Start Accounting (Tables)
Fresh Start Accounting (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Reorganizations [Abstract] | |
Schedule of Reconciliation of Enterprise Value to Fair Value of Successor Equity | The following table reconciles the enterprise value to the estimated fair value of the Successor's equity at the Effective Date (in thousands): Enterprise value $ 559,205 Less: Fair value of noncontrolling interest (242,200) Enterprise value of Unit interests 317,005 Plus: Cash and cash equivalents 25,482 Plus: Restricted cash 7,458 Less: Fair value of capital leases (4,622) Less: Fair value of debt (including the fair value of current debt) (148,000) Fair value of Successor equity $ 197,323 |
Schedule of Reconciliation of Enterprise Value to the Reorganization Value | The following table reconciles the enterprise value to the reorganization value of the Successor’s assets as of the Effective Date (in thousands): Enterprise value $ 559,205 Plus: Cash and cash equivalents 25,482 Plus: Restricted cash 7,458 Plus: Current liabilities (excluding the fair value of capital leases and current debt) 86,897 Plus: Long-term asset retirement obligation 22,415 Plus: Other long-term liabilities (excluding long-term asset retirement obligation) 24,886 Reorganization value of Successor assets $ 726,343 |
Schedule of Fresh-Start Adjustments | As of September 1, 2020 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments (11) Successor ASSETS (In thousands) Current assets: Cash and cash equivalents $ 32,280 $ (6,798) (2) $ — $ 25,482 Restricted cash — 7,458 (3) — 7,458 Accounts receivable, net 50,621 — — 50,621 Materials and supplies 64 — (64) (12) — Current income tax receivable 850 — — 850 Prepaid expenses and other 13,692 6,382 (4) (990) (13) 19,084 Total current assets 97,507 7,042 (1,054) 103,495 Property and equipment: Oil and natural gas properties, on the full cost method: Proved properties 6,539,816 — (6,301,532) (14) 238,284 Unproved properties not being amortized 30,205 — (30,205) (14) — Drilling equipment 1,285,024 — (1,221,566) (15) 63,458 Gas gathering and processing equipment 833,788 — (583,690) (15) 250,098 Saltwater disposal systems 43,541 — (43,541) (15) — Land and building 59,080 — (26,445) (15) 32,635 Transportation equipment 15,577 — (12,263) (15) 3,314 Other 57,427 — (47,469) (15) 9,958 8,864,458 — (8,266,711) 597,747 Less accumulated depreciation, depletion, amortization, and impairment 7,923,868 — (7,923,868) (14) (15) — Net property and equipment 940,590 — (342,843) 597,747 Right of use asset 7,476 — (659) (16) 6,817 Other assets 24,666 (6,382) (4) — 18,284 Total assets $ 1,070,239 $ 660 $ (344,556) $ 726,343 As of September 1, 2020 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments (11) Successor LIABILITIES AND SHAREHOLDERS’ EQUITY (In thousands) Current liabilities: Accounts payable $ 27,354 $ 6,382 (4) $ — $ 33,736 Accrued liabilities 36,990 (4,115) (5) — 32,875 Current operating lease liability 4,643 — (669) (16) 3,974 Current portion of long-term debt 124,000 (123,600) (6) — 400 Current derivative liabilities 5,089 — — 5,089 Warrant liability — — 885 (17) 885 Current portion of other long-term liabilities 11,201 3,743 (7) 16 (18) 14,960 Total current liabilities 209,277 (117,590) 232 91,919 Long-term debt 16,000 131,600 (6) — 147,600 Non-current derivative liabilities 766 — — 766 Operating lease liability 2,760 — 11 (16) 2,771 Other long-term liabilities 61,393 (3,220) (4) (7) (14,409) (18) 43,764 Liabilities subject to compromise 762,215 (762,215) (8) — — Deferred income taxes 4,466 — (4,466) (19) — Commitments and contingencies Shareholders’ equity: Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019 — — — — Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019 10,704 (10,704) (9) — — Predecessor capital in excess of par value 650,153 (650,153) (9) — — Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 1, 2020 — — — — Successor common stock, $0.01 par value, 25,000,000 authorized, 12,000,000 issued at September 1, 2020 — 120 (8) — 120 Successor capital in excess of par value — 197,203 (8) — 197,203 Retained earnings (deficit) (818,679) 1,215,619 (10) (396,940) (20) — Total shareholders’ equity attributable to Unit Corporation (157,822) 752,085 (396,940) 197,323 Non-controlling interests in consolidated subsidiaries 171,184 — 71,016 (21) 242,200 Total shareholders' equity 13,362 752,085 (325,924) 439,523 Total liabilities and shareholders’ equity $ 1,070,239 $ 660 $ (344,556) $ 726,343 Reorganization Adjustments (1) Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes. (2) The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands): Funding of the professional fees escrow account $ (7,458) Proceeds from Exit credit facility 8,000 Payment of debt issuance costs on the Exit credit facility (3,225) Payment of professional fees (3,943) Payment of accrued interest payable under the Predecessor credit facility (172) Changes in cash and cash equivalents $ (6,798) (3) Represents the reserve for professional fee escrow of $7.5 million. (4) Represents the reclassification of other long-term assets related to deferred compensation to prepaid expenses and other assets as the deferred compensation payout must be paid within 12 months from the date of emergence under the Plan. Simultaneously, the current portion of deferred compensation liability was reclassified from other long-term liabilities to accounts payable. (5) Represents the payment of the DIP facility interest of $0.2 million and professional fees for $3.9 million. (6) Represents the transition of the DIP Credit Agreement and the Predecessor Credit Agreement of $124.0 million into the Exit Facility and issuing an additional $8.0 million of borrowings under the Exit Credit Agreement. (7) Represents the reclassification of the short-term portion of the separation benefit liabilities from non-current to current liabilities which was offset by the increase in non-current portion of liabilities. (8) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands): Liabilities subject to compromise before the Effective Date: 6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date) $ 672,369 Accounts payable 1,179 Employee separation benefit plan obligations 23,394 Litigation settlements 45,000 Royalty suspense accounts payable 20,273 Total liabilities subject to compromise 762,215 Separation settlement treatment (6,905) Successor Common Stock and APIC (1) issued to allowed claim holders (175,521) Successor Common Stock and APIC for disputed claims reserve (11,936) Gain on settlement of liabilities subject to compromise $ 567,853 (1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise. (9) Represents the cancellation of Old Common Stock. (10) Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above. Fresh Start Adjustments (11) Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below. (12) Represents the reclassification of materials and supplies to proved properties. (13) Represents the write off of the Predecessor's unamortized debt fees related to the DIP facility. (14) Reflects a decrease of oil and natural gas properties, net, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Proved properties $ 238,284 $ 6,539,816 Unproved properties — 30,205 238,284 6,570,021 Less accumulated depletion, amortization, and impairment — (6,305,113) $ 238,284 $ 264,908 (15) Reflects a decrease in fair value of drilling equipment, gas gathering and processing equipment, saltwater disposal systems, land and building, transportation equipment, and other property and equipment and the elimination of accumulated depreciation, based on the methodologies discussed above. The following table summarizes the components of other property and equipment as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Drilling equipment $ 63,458 $ 1,285,024 Gas gathering and processing equipment 250,098 833,788 Saltwater disposal systems — 43,541 Land and building 32,635 59,080 Transportation equipment 3,314 15,577 Other 9,958 57,427 359,463 2,294,437 Less accumulated depreciation and impairment — (1,618,754) $ 359,463 $ 675,683 (16) Reflects the valuation adjustments to the company’s right of use assets, current operating lease liability, and operating lease liability, adjusted for fair value of favorable and unfavorable lease terms, and the revised incremental borrowing rates of the Successor. (17) Represents the liability for the Warrants using a Black-Scholes-Merton model which uses various market-based inputs including: stock prices, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield. (18) Represents the reclassification of the short-term portion of ARO from non-current liabilities to current and the fair value adjustment, which was determined using our fresh start updates to these obligations, including the application of the Successor's credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of well plugging activity, and resetting all ARO to a single layer. (19) Represents the adjustments to deferred tax liability as a result of the cumulative tax impact of the fresh start adjustments. The significant revisions to the carrying value of our assets and liabilities because of applying fresh start accounting resulted in the company increasing its overall net deferred tax asset position on emergence from bankruptcy. Besides the changes in book value, the company has as of the Effective Date, approximately $726.4 million of net operating losses (NOLs) carried forward to offset taxable income in the future years. Approximately $584.2 million of this NOL will expire commencing in fiscal 2021 through 2037. The NOLs of approximately $142.2 million from years ended after December 31, 2017 have an indefinite carryforward period. The amount of these NOLs which is available to offset future income may be severely limited due to change-in-control tax provisions. Because of our history of operating losses and the uncertainty surrounding the realization of the deferred tax assets in future years, we have determined that it is more likely than not that the deferred tax assets will not be realized in future periods. Accordingly, we recorded a 100% valuation allowance against our net deferred tax assets. (20) Represents the cumulative impact of the fresh start accounting adjustments discussed above. |
Schedule of reorganization items | The following table summarizes the components included in "Reorganization items, net" in our Consolidated Statements of Operations for the periods presented: Successor Predecessor Four Months Ended Eight Months Ended December 31, 2020 August 31, (In thousands) Gains on settlement of liabilities subject to compromise $ — $ (567,853) Fresh start accounting adjustments — 401,406 Legal and professional fees and expenses 2,273 15,745 Acceleration of Predecessor stock compensation expense — 1,431 Exit Facility fees — 3,225 5% Exit Facility equity fee — 9,866 Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021 — 2,205 Total reorganization items, net $ 2,273 $ (133,975) |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accounting Policies [Abstract] | |
Schedule of Segment's Revenue [Table Text Block] | Below are the third-party customers that accounted for over 10% of each of our segment’s revenues: Successor Predecessor Period Period For the Year Ended Oil and Natural Gas: CVR Refining, LP 14 % 15 % 14 % Plains Marketing L.P. * 11 % * Drilling: EOG Resources, Inc. 28 % 20 % 12 % QEP Resources, Inc. 23 % 10 % 12 % Citizen Energy III, LLC 16 % * * Slawson Exploration Company, Inc. 16 % 21 % 11 % Cimarex Energy Co. 12 % * * Mid-Stream: ONEOK, Inc. 28 % 31 % 33 % Range Resources Corporation 15 % 21 % 13 % Centerpoint Energy Service, Inc. * * 10 % _______________________ * Revenue accounted for less than 10% of the segment's revenues. |
Schedule of Fair Values of the Net Assets (Liabilities) [Table Text Block] | At December 31, 2020, the fair values of the net liabilities we had with each of the counterparties regarding our commodity derivative transactions are listed in the table below: December 31, 2020 (In millions) Bank of Oklahoma $ (5.4) Bank of Montreal (0.3) Total net liabilities $ (5.7) |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue, Remaining Performance Obligation | Included below is the adjustment to demand fees from adopting ASC 606 over the remaining term of the contracts as of December 31, 2020. Contract Remaining Term of Contract 2021 2022 2023 and beyond Total Remaining Impact to Revenue Demand fee contracts 2-8 years $ (3,501) $ 1,380 $ 36 $ (2,085) |
Contract with Customer, Asset and Liability | The adjustment to revenue for these demand fees was $(3.8) million and $2.6 million in 2020 and 2019, respectively. Successor Predecessor Classification on the Consolidated Balance Sheets December 31, 2020 December 31, Change (In thousands) Assets Current contract assets Prepaid expenses and other $ 6,084 $ 6,664 $ (580) Non-current contract assets Other assets 173 6,257 (6,084) Total contract assets $ 6,257 $ 12,921 $ (6,664) Liabilities Current contract liabilities Current portion of other long-term liabilities $ 2,583 $ 2,889 $ (306) Non-current contract liabilities Other long-term liabilities 1,589 4,172 (2,583) Total contract liabilities 4,172 7,061 (2,889) Contract assets (liabilities), net $ 2,085 $ 5,860 $ (3,775) |
Earnings (Loss) Per Share (Tabl
Earnings (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings (Loss) Per Share [Table Text Block] | Information related to the calculation of loss per share attributable to the company is: Income (Loss) (Numerator) Weighted Per-Share (In thousands except per share amounts) For the four months ended December 31, 2020 Basic loss attributable to Unit Corporation per common share $ (18,140) 12,000 $ (1.51) Predecessor Period Information related to the calculation of loss per share attributable to the company is: Income (Loss) (Numerator) Weighted Shares (Denominator) Per-Share Amount (In thousands except per share amounts) For the year ended December 31, 2019: Basic loss attributable to Unit Corporation per common share $ (553,879) 52,849 $ (10.48) Effect of dilutive stock options and restricted stock — — — Diluted loss attributable to Unit Corporation per common share $ (553,879) 52,849 $ (10.48) For the eight months ended August 31, 2020 Basic loss attributable to Unit Corporation per common share $ (931,012) 53,368 $ (17.45) |
Schedule of Antidilutive Securities Excluded from Computation of Earnings (Loss) Per Share [Table Text Block] | The following options were not included in the weighted shares above as their affect would be anti-dilutive to the computation of loss per share for the year ended December 31: 2019 Stock options 42,000 Average exercise price $ 48.56 |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Accrued Liabilities [Abstract] | |
Accrued Liabilities [Table Text Block] | Accrued liabilities consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) Employee costs $ 8,878 $ 17,832 Lease operating expenses 6,405 9,200 Taxes 2,324 3,450 Legal settlement (Note 18) 2,070 — Interest payable 884 6,562 Third-party credits — 3,691 Other 1,182 5,827 Total accrued liabilities $ 21,743 $ 46,562 |
Long-Term Debt And Other Long_2
Long-Term Debt And Other Long-Term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Long-term debt and other long-term liabilites [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | Long-term debt consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) Current portion of long-term debt: Predecessor credit facility with an average interest rate of 4.0% $ — $ 108,200 Successor Exit Facility with an average interest rate of 6.6% 600 — Long-term debt: Successor Exit Facility with an average interest of 6.6% 98,400 — Superior credit agreement with an average interest rate of 3.9% at December 31, 2019 — 16,500 Predecessor 6.625% senior subordinated notes due 2021 — 650,000 Total principal amount $ 98,400 $ 666,500 Less: unamortized discount — (971) Less: debt issuance costs, net — (2,313) Total long-term debt $ 98,400 $ 663,216 |
Other Long Term Liabilities [Table Text Block] | Other long-term liabilities consisted of the following as of December 31: Successor Predecessor 2020 2019 (In thousands) ARO liability $ 23,356 $ 66,627 Workers’ compensation 10,164 11,510 Separation benefit plans (1) 4,201 10,122 Contract liability 4,172 7,061 Gas balancing liability 3,997 3,838 Finance lease obligations 3,216 7,379 Other long-term liability 1,321 — Deferred compensation plan — 6,180 50,427 112,717 Less current portion 11,168 17,376 Total other long-term liabilities $ 39,259 $ 95,341 _______________________ |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule Of Asset Retirement Obligations [Table Text Block] | The following table shows certain information about our estimated AROs for the periods indicated (in thousands): ARO liability, December 31, 2019 (Predecessor) 66,627 Accretion of discount 1,545 Liability incurred 465 Liability settled (838) Liability sold (487) Revision of estimates (1) (28,328) ARO liability, August 31, 2020 (Predecessor) 38,984 Fresh start adjustments (14,393) ARO liability, August 31, 2020 (Successor) 24,591 Accretion of discount 467 Liability incurred 151 Liability settled (95) Liability sold — Revision of estimates (1) (1,758) ARO liability, December 31, 2020 (Successor) 23,356 Less current portion (Successor) 2,121 Total long-term ARO (Successor) $ 21,235 _______________________ |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |
Reconciliation Of Income Tax Expense (Benefit) [Table Text Block] | A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows: Successor Predecessor Period Period For the Year Ended (In thousands) Income tax benefit computed by applying the statutory rate $ (3,001) $ (190,103) $ (144,092) State income tax benefit, net of federal benefit (500) (31,684) (21,733) Deferred tax liability revaluation — — — Restricted stock shortfall — 7,404 347 Non-controlling interest in Superior (1,017) 7,504 (11) Goodwill impairment — — 12,346 Valuation allowance 4,047 177,284 19,654 Reorganization adjustments — 14,152 — Statutory depletion and other 169 813 1,163 Income tax benefit $ (302) $ (14,630) $ (132,326) |
Schedule Of Total Provision For Income Taxes [Table Text Block] | For the periods indicated, the total provision for income taxes consisted of the following: Successor Predecessor Period Period For the Year Ended (In thousands) Current taxes: Federal $ — $ (917) $ (918) State (302) — (363) (302) (917) (1,281) Deferred taxes: Federal — (16,663) (108,440) State — 2,950 (22,605) — (13,713) (131,045) Total provision $ (302) $ (14,630) $ (132,326) |
Schedule Of Deferred Tax Assets And Liabilities [Table Text Block] | Deferred tax assets and liabilities are comprised of the following at December 31: Successor Predecessor 2020 2019 (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 22,051 $ 31,822 Net operating loss carryforward 100,236 246,927 Depreciation, depletion, amortization, and impairment 80,947 — Alternative minimum tax and research and development tax credit carryforward 1,738 2,656 204,972 281,405 Deferred tax liability: Depreciation, depletion, amortization, and impairment — (226,034) Investment in Superior (3,987) (49,430) Net deferred tax asset (liability) 200,985 5,941 Valuation allowance (200,985) (19,654) Non-current—deferred tax liability $ — $ (13,713) |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Share-based Payment Arrangement [Abstract] | |
Schedule Of Restricted Stock Awards [Table Text Block] | For restricted stock awards, we had: Predecessor Period For the Year Ended (In millions) Recognized stock compensation expense (1) $ 6.1 $ 12.8 Capitalized stock compensation cost for our oil and natural gas properties $ — $ 2.4 Tax benefit on stock-based compensation $ 1.5 $ 3.1 _______________________ |
Activity Pertaining To Restricted Stock Awards [Table Text Block] | Activity pertaining to restricted stock awards granted under the amended plan is as follows: Employees Number of Time Vested Shares Number of Performance Vested Shares Total Number of Shares Weighted Average Price Nonvested at January 1, 2019 (Predecessor) 1,268,883 608,125 1,877,008 $ 19.70 Granted 927,173 500,256 1,427,429 16.09 Vested (570,107) (233,835) (803,942) 15.56 Forfeited (98,301) (33,172) (131,473) 19.36 Nonvested at December 31, 2019 (Predecessor) 1,527,648 841,374 2,369,022 $ 18.95 Granted — — — — Vested (677,076) — (677,076) 19.95 Forfeited (272,396) (503,809) (776,205) 19.28 Nonvested at August 31, 2020 (Predecessor) 578,176 337,565 915,741 $ 17.92 Cancelled (578,176) (337,565) (915,741) 17.92 Nonvested at September 1, 2020 (Successor) — — — $ — Non-Employee Directors Number of Shares Weighted Average Price Nonvested at January 1, 2019 (Predecessor) 107,045 $ 17.07 Granted 72,784 12.09 Vested (61,141) 15.49 Forfeited — — Nonvested at December 31, 2019 (Predecessor) 118,688 $ 14.83 Granted — — Vested (48,475) 15.88 Forfeited — — Nonvested at August 31, 2020 (Predecessor) 70,213 $ 14.10 Cancelled (70,213) 14.10 Nonvested at September 1, 2020 (Successor) — $ — |
Activity Pertaining to Nonemployee Director Stock Award Plan [Table Text Block] | Activity pertaining to the Directors’ Plan is as follows: Number of Shares Weighted Average Exercise Price Nonvested at January 1, 2019 (Predecessor) 66,500 $ 44.42 Granted — — Exercised — — Forfeited (24,500) 37.31 Nonvested at December 31, 2019 (Predecessor) 42,000 $ 48.56 Granted — — Exercised — — Forfeited (14,000) 41.21 Outstanding at August 31, 2020 (Predecessor) 28,000 $ 52.24 Cancelled (28,000) 52.24 Outstanding at September 1, 2020 (Successor) — $ — |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Non-designated Hedges Outstanding [Table Text Block] | At December 31, 2020, the following non-designated hedges were outstanding: Term Commodity Contracted Volume Weighted Average Fixed Price for Swaps Contracted Market Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215) NGPL TEXOK Jan'21 - Oct'21 Natural gas - swap 50,000 MMBtu/day $2.818 IF - NYMEX (HH) Nov'21 - Dec'21 Natural gas - swap 45,000 MMBtu/day $2.900 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - swap 5,000 MMBtu/day $2.605 IF - NYMEX (HH) Jan'23 - Dec'23 Natural gas - swap 22,000 MMBtu/day $2.456 IF - NYMEX (HH) Jan'22 - Dec'22 Natural gas - collar 35,000 MMBtu/day $2.50 - $2.68 IF - NYMEX (HH) Jan'21 - Dec'21 Crude oil - swap 3,000 Bbl/day $44.65 WTI - NYMEX Jan'22 - Dec'22 Crude oil - swap 2,300 Bbl/day $42.25 WTI - NYMEX Jan'23 - Dec'23 Crude oil - swap 1,300 Bbl/day $43.60 WTI - NYMEX |
Fair Value Of Derivative Instruments And Locations In Balance Sheets [Table Text Block] | The following tables present the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31: Derivative Assets Fair Value Successor Predecessor Balance Sheet Location 2020 2019 (In thousands) Commodity derivatives: Current Current derivative assets $ — $ 633 Long-term Non-current derivative assets — — Total derivative assets $ — $ 633 Derivative Liabilities Fair Value Successor Predecessor Balance Sheet Location 2020 2019 (In thousands) Commodity derivatives: Current Current derivative liabilities $ 1,047 $ — Long-term Non-current derivative liabilities 4,659 27 Total derivative liabilities $ 5,706 $ 27 |
Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments [Table Text Block] | The following is the Effect of derivative instruments on the Consolidated Statements of Operations for the periods indicated: Derivatives Instruments Location of Gain or (Loss) Recognized in Income on Derivative Amount of Gain or (Loss) Recognized in Income on Derivative Successor Predecessor Period Period For the Year Ended (In thousands) Commodity derivatives Gain (loss) on derivatives, included are amounts settled during the period of $(1,133), $(4,244), and $16,196, respectively $ (985) $ (10,704) $ 4,225 Total $ (985) $ (10,704) $ 4,225 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Recurring Fair Value Measurements [Table Text Block] | The following tables set forth our recurring fair value measurements: Successor December 31, 2020 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 3,436 $ — $ (3,436) $ — Liabilities (9,142) — 3,436 (5,706) $ (5,706) $ — $ — $ (5,706) Predecessor December 31, 2019 Level 2 Level 3 Effect of Netting Total (In thousands) Financial assets (liabilities): Commodity derivatives: Assets $ 177 $ 1,204 $ (748) $ 633 Liabilities (775) — 748 (27) $ (598) $ 1,204 $ — $ 606 |
Reconciliations Of Level 3 Fair Value Measurements [Table Text Block] | The following tables are reconciliations of our recurring level 3 fair value measurements: Net Derivatives Successor Predecessor Period Period For the Year Ended (In thousands) Beginning of period $ — $ 1,204 $ 10,630 Total gains or losses: Included in earnings — 978 (1,494) Settlements — (2,182) (7,932) End of period $ — $ — $ 1,204 Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period $ — $ (1,204) $ (9,426) |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Leases [Abstract] | |
Operating leases | The following table sets forth the maturity of our operating lease liabilities as of December 31, 2020: Amount (In thousands) Ending December 31, 2021 $ 4,232 2022 1,305 2023 96 2024 12 2025 12 2026 and beyond 63 Total future payments 5,720 Less: Interest 200 Present value of future minimum operating lease payments 5,520 Less: Current portion 4,075 Total long-term operating lease payments $ 1,445 |
Finance leases | Future payments required under the finance leases at December 31, 2020 are as follows: Amount Ending December 31, (In thousands) 2021 $ 3,774 Total future payments 3,774 Less payments related to: Maintenance 525 Interest 33 Present value of future minimum payments 3,216 Less: Current portion 3,216 Total long-term finance lease payments $ — |
Schedule of lease assets and liabilities | Information about our lease assets and liabilities included in our Consolidated Balance Sheets as of December 31, 2020 and 2019 are as follows: Successor Predecessor Classification on the Consolidated Balance Sheets December 31, December 31, (In thousands) Assets Operating right of use assets Right of use assets $ 5,592 $ 5,673 Finance right of use assets Property, plant, and equipment, net 7,281 17,396 Total right of use assets $ 12,873 $ 23,069 Liabilities Current liabilities: Operating lease liabilities Current operating lease liabilities $ 4,075 $ 3,430 Finance lease liabilities Current portion of other long-term liabilities 3,216 4,164 Non-current liabilities: Operating lease liabilities Operating lease liabilities 1,445 2,071 Finance lease liabilities Other long-term liabilities — 3,215 Total lease liabilities $ 8,736 $ 12,880 |
Schedule of lease costs | The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated: Successor Predecessor Period Period Year Ended December 31, 2019 (In thousands) Components of total lease cost: Amortization of finance leased assets $ 1,406 $ 2,757 $ 4,001 Interest on finance lease liabilities 54 165 382 Operating lease cost 1,331 3,604 4,034 Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of less than $0.2 million, $1.5 million, and $24.7 million, respectively 3,664 8,190 38,868 Variable lease cost 64 223 351 Total lease cost $ 6,519 $ 14,939 $ 47,636 |
Supplemental cash flow information related to leases | The following table provides supplemental cash flow information related to leases for the periods indicated: Successor Predecessor Period Period Year Ended December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 1,489 $ 3,849 $ 4,034 Financing cash flows for finance leases 1,407 2,757 4,001 Lease liabilities recognized in exchange for new operating lease right of use assets — — 5 |
Schedule of weighted average discount rate for leases | The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases at December 31, 2020: Weighted Average Remaining Lease Term Weighted Average Discount Rate (1) (In years) Operating leases 1.6 4.41% Finance leases 0.7 4.00% _______________________ 1. Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease. |
Variable Interest Entity Arra_2
Variable Interest Entity Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Variable Interest Entity Arrangements [Abstract] | |
Schedule of Assets and Liabilities | The assets and liabilities of Superior at December 31, 2020 include the company’s application of fresh start accounting as described in Note 3 - Fresh Start Accounting, while the asset and liabilities at December 31, 2019, reflect historical basis, prior to any fresh start accounting adjustments. The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the Consolidated Balance Sheets. December 31, December 31, (In thousands) Current assets: Cash and cash equivalents $ 11,642 $ — Accounts receivable 27,427 21,073 Prepaid expenses and other 6,746 7,686 Total current assets 45,815 28,759 Property and equipment: Gas gathering and processing equipment 251,403 824,699 Transportation equipment 1,748 3,390 253,151 828,089 Less accumulated depreciation, depletion, amortization, and impairment 10,466 407,144 Net property and equipment 242,685 420,945 Right of use assets 2,823 3,948 Other assets 2,309 9,442 Total assets $ 293,632 $ 463,094 Current liabilities: Accounts payable $ 17,045 $ 18,511 Accrued liabilities 3,777 4,198 Current operating lease liability 1,762 2,407 Current portion of other long-term liabilities 5,799 7,060 Total current liabilities 28,383 32,176 Long-term debt less debt issuance costs — 16,500 Operating lease liability 1,013 1,404 Other long-term liabilities 1,589 8,126 Total liabilities $ 30,985 $ 58,206 |
Industry Segment Information (T
Industry Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Segment Reporting [Abstract] | |
Revenue From Different Segments [Table Text Block] | The following table provides certain information about the operations of each of our segments: Successor Four Months Ended December 31, 2020 Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated (In thousands) Revenues: (1) Oil and natural gas $ 57,580 $ — $ — $ — $ (2) $ 57,578 Contract drilling — 19,413 — — — 19,413 Gas gathering and processing — — 68,369 — (11,832) 56,537 Total revenues 57,580 19,413 68,369 — (11,834) 133,528 Expenses: Operating costs: Oil and natural gas 26,111 — — — (855) 25,256 Contract drilling — 13,852 — — — 13,852 Gas gathering and processing — — 53,147 — (10,978) 42,169 Total operating costs 26,111 13,852 53,147 — (11,833) 81,277 Depreciation, depletion, and amortization 14,869 2,102 10,659 332 — 27,962 Impairments (2) 26,063 — — — — 26,063 Total expenses 67,043 15,954 63,806 332 (11,833) 135,302 General and administrative — — — 6,702 — 6,702 Gain on disposition of assets (24) (521) (55) (19) — (619) Income (loss) from operations (9,439) 3,980 4,618 (7,015) (1) (7,857) Loss on derivatives — — — (985) — (985) Reorganization items, net — — — (2,273) — (2,273) Interest, net — — (501) (2,774) — (3,275) Other 56 4 34 6 — 100 Income (loss) before income taxes $ (9,383) $ 3,984 $ 4,151 $ (13,041) $ (1) $ (14,290) Identifiable assets: Oil and natural gas (3) $ 236,073 $ — $ — $ — $ (3,326) $ 232,747 Contract drilling — 81,612 — — (4) 81,608 Gas gathering and processing — — 293,632 — (335) 293,297 Total identifiable assets (4) 236,073 81,612 293,632 — (3,665) 607,652 Corporate land and building — — — 32,382 — 32,382 Other corporate assets (5) — — — 13,671 (4,002) 9,669 Total assets $ 236,073 $ 81,612 $ 293,632 $ 46,053 $ (7,667) $ 649,703 Capital expenditures: $ 4,018 $ 616 $ 1,323 $ 3 $ — $ 5,960 _______________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax. 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. Predecessor Eight Months Ended August 31, 2020 Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 103,443 $ — $ — $ — $ (4) $ 103,439 Contract drilling — 73,519 — — — 73,519 Gas gathering and processing — — 114,531 — (14,532) 99,999 Total revenues (1) 103,443 73,519 114,531 — (14,536) 276,957 Expenses: Operating costs: Oil and natural gas 119,664 — — — (1,973) 117,691 Contract drilling — 51,811 — — (1) 51,810 Gas gathering and processing — — 80,607 — (12,562) 68,045 Total operating costs 119,664 51,811 80,607 — (14,536) 237,546 Depreciation, depletion, and amortization 68,762 15,544 29,371 1,819 — 115,496 Impairments (2) 393,726 410,126 63,962 — — 867,814 Total expenses 582,152 477,481 173,940 1,819 (14,536) 1,220,856 Loss on abandonment of assets 17,641 1,092 — — — 18,733 General and administrative — — — 42,766 — 42,766 (Gain) loss on disposition of assets (160) (1,390) (18) 1,479 — (89) Loss from operations (496,190) (403,664) (59,391) (46,064) — (1,005,309) Loss on derivatives — — — (10,704) — (10,704) Write-off of debt issuance costs — — — (2,426) — (2,426) Reorganization items, net 15,504 (183,664) (71,016) 373,151 — 133,975 Interest, net — — (1,888) (20,936) — (22,824) Other 458 1,449 50 77 — 2,034 Income (loss) before income taxes $ (480,228) $ (585,879) $ (132,245) $ 293,098 $ — $ (905,254) Capital expenditures: $ 5,350 $ 2,438 $ 9,342 $ 83 $ — $ 17,213 _______________________ ____________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. Predecessor Year Ended December 31, 2019 Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated (In thousands) Revenues: Oil and natural gas $ 325,797 $ — $ — $ — $ — $ 325,797 Contract drilling — 184,192 — — (15,809) 168,383 Gas gathering and processing — — 227,939 — (47,485) 180,454 Total revenues (1) 325,797 184,192 227,939 — (63,294) 674,634 Expenses: Operating costs: Oil and natural gas 140,026 — — — (4,902) 135,124 Contract drilling — 130,188 — — (14,190) 115,998 Gas gathering and processing — — 176,189 — (42,583) 133,606 Total operating costs 140,026 130,188 176,189 — (61,675) 384,728 Depreciation, depletion, and amortization 168,651 51,552 47,663 7,707 — 275,573 Impairments (2) 559,867 62,809 3,040 — — 625,716 Total expenses 868,544 244,549 226,892 7,707 (61,675) 1,286,017 General and administrative — — — 38,246 — 38,246 (Gain) loss on disposition of assets (199) 3,872 (160) (11) — 3,502 Income (loss) from operations (542,548) (64,229) 1,207 (45,942) (1,619) (653,131) Gain on derivatives — — — 4,225 — 4,225 Interest expense, net — — (1,546) (35,466) — (37,012) Other (481) (605) 827 23 — (236) Income (loss) before income taxes $ (543,029) $ (64,834) $ 488 $ (77,160) $ (1,619) $ (686,154) Identifiable assets: Oil and natural gas (3) 851,662 — — — (4,264) 847,398 Contract drilling — 708,510 — — (42) 708,468 Gas gathering and processing — — 463,699 — (4,255) 459,444 Total identifiable assets (4) 851,662 708,510 463,699 — (8,561) 2,015,310 Corporate land and building — — — 54,155 — 54,155 Other corporate assets (5) — — — 23,092 (2,505) 20,587 Total assets $ 851,662 $ 708,510 $ 463,699 $ 77,247 $ (11,066) $ 2,090,052 Capital expenditures: $ 268,622 $ 40,636 $ 64,438 $ 673 $ — $ 374,369 _______________________ 1. The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. 2. We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). 3. Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. 4. Identifiable assets are those used in Unit’s operations in each industry segment. 5. Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
Selected Quarterly Financial _2
Selected Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Selected Quarterly Financial Information [Abstract] | |
Schedule Of Quarterly Financial Information [Table Text Block] | Summarized unaudited quarterly financial information is as follows: First Second Third Quarter (1) Fourth (In thousands except per share amounts) 2020 (Successor) Revenues $ — $ — $ 32,846 $ 100,682 Gross income (loss) (2) $ — $ — $ (7,373) $ 5,599 Net loss attributable to Unit Corporation $ — $ — $ (8,968) (3) $ (9,172) (4) Net loss attributable to Unit Corporation per common share: Basic $ — $ — $ (0.75) $ (0.76) Diluted $ — $ — $ (0.75) $ (0.76) 2020 (Predecessor) Revenues $ 122,376 $ 89,007 $ 65,574 $ — Gross loss (2) $ (764,888) $ (171,374) $ (7,637) $ — Net income (loss) attributable to Unit Corporation $ (770,494) (5) $ (215,649) (6) $ 55,131 (7) $ — Net income (loss) attributable to Unit Corporation per common share: Basic $ (14.50) $ (4.03) $ 1.03 $ — Diluted $ (14.50) $ (4.03) $ 1.03 $ — 2019 (Predecessor) Revenues $ 189,691 $ 165,146 $ 155,439 $ 164,358 Gross income (loss) (2) $ 24,095 $ 813 $ (242,308) $ (393,983) Net loss attributable to Unit Corporation $ (3,504) $ (8,509) $ (206,886) (8) $ (334,980) (9) Net loss attributable to Unit Corporation per common share: Basic $ (0.07) $ (0.16) $ (3.91) $ (6.33) Diluted $ (0.07) $ (0.16) $ (3.91) $ (6.33) _________________________ 1. Third quarter for the 2020 Predecessor Period is for the period July 1, 2020 through August 31, 2020. Third quarter for the 2020 Successor Period is the period September 1, 2020 through September 30, 2020. 2. Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, loss on abandonment of assets, gain (loss) on derivatives, reorganization items, net, income taxes, and other income (loss). 3. During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. 4. During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax. 5. During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets. 6. During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax. 7. During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net. 8. During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax). 9. During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax). |
Supplemental Condensed Consol_2
Supplemental Condensed Consolidating Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Condensed Financial Information Disclosure [Abstract] | |
Condensed Consolidating Balance Sheet | Condensed Consolidating Balances Sheets Predecessor December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 503 $ 68 $ — $ — $ 571 Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216) 2,645 64,805 24,653 (9,447) 82,656 Materials and supplies — 449 — — 449 Current derivative asset 633 — — — 633 Income tax receivable 1,756 — — — 1,756 Assets held for sale — 5,908 — — 5,908 Prepaid expenses and other 2,019 3,373 7,686 — 13,078 Total current assets 7,556 74,603 32,339 (9,447) 105,051 Property and equipment: Oil and natural gas properties on the full cost method: Proved properties — 6,341,582 — — 6,341,582 Unproved properties not being amortized — 252,874 — — 252,874 Drilling equipment — 1,295,713 — — 1,295,713 Gas gathering and processing equipment — — 824,699 — 824,699 Saltwater disposal systems — 69,692 — — 69,692 Corporate land and building — 59,080 — — 59,080 Transportation equipment 9,712 16,621 3,390 — 29,723 Other 28,927 29,065 — — 57,992 38,639 8,064,627 828,089 — 8,931,355 Less accumulated depreciation, depletion, amortization, and impairment 33,794 6,537,731 407,144 — 6,978,669 Net property and equipment 4,845 1,526,896 420,945 — 1,952,686 Intercompany receivable 1,048,785 — — (1,048,785) — Investments 865,252 — — (865,252) — Right of use asset 46 1,733 3,948 (54) 5,673 Other assets 8,107 9,094 9,441 — 26,642 Total assets $ 1,934,591 $ 1,612,326 $ 466,673 $ (1,923,538) $ 2,090,052 Predecessor December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $ 12,259 $ 61,002 $ 18,511 $ (7,291) $ 84,481 Accrued liabilities 28,003 14,024 6,691 (2,156) 46,562 Current operating lease liability 20 1,009 2,407 (6) 3,430 Current portion of long-term debt 108,200 — — — 108,200 Current portion of other long-term liabilities 3,003 7,313 7,060 — 17,376 Total current liabilities 151,485 83,348 34,669 (9,453) 260,049 Intercompany debt — 1,047,599 1,186 (1,048,785) — Long-term debt less debt issuance costs 646,716 — 16,500 — 663,216 Non-current derivative liability 27 — — — 27 Operating lease liability 25 690 1,404 (48) 2,071 Other long-term liabilities 12,553 74,662 8,126 — 95,341 Deferred income taxes 68,150 (54,437) — — 13,713 Total shareholders' equity 1,055,635 460,464 404,788 (865,252) 1,055,635 Total liabilities and shareholders’ equity $ 1,934,591 $ 1,612,326 $ 466,673 $ (1,923,538) $ 2,090,052 |
Condensed Consolidating Statements of Operations | Condensed Consolidating Statements of Operations Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 176,962 $ 114,531 $ (14,536) $ 276,957 Expenses: Operating costs — 171,476 80,607 (14,537) 237,546 Depreciation, depletion, and amortization 1,819 84,306 29,371 — 115,496 Impairments — 803,852 63,962 — 867,814 Loss on abandonment of assets — 18,733 — — 18,733 General and administrative — 42,766 — — 42,766 (Gain) loss on disposition of assets 1,479 (1,550) (18) — (89) Total operating costs 3,298 1,119,583 173,922 (14,537) 1,282,266 Income (loss) from operations (3,298) (942,621) (59,391) 1 (1,005,309) Interest, net (20,936) — (1,888) — (22,824) Write-off of debt issuance costs (2,426) — — — (2,426) Loss on derivatives (10,704) — — — (10,704) Reorganization items 373,151 (168,160) (71,016) — 133,975 Other, net 79 1,906 49 — 2,034 Income (loss) before income taxes 335,866 (1,108,875) (132,246) 1 (905,254) Income tax benefit (14,630) — — — (14,630) Equity in net earnings from investment in subsidiaries, net of taxes (1,241,120) — — 1,241,120 — Net loss (890,624) (1,108,875) (132,246) 1,241,121 (890,624) Less: net income attributable to non-controlling interest 40,388 — 40,388 (40,388) 40,388 Net loss attributable to Unit Corporation $ (931,012) $ (1,108,875) $ (172,634) $ 1,281,509 $ (931,012) Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Revenues $ — $ 494,180 $ 227,939 $ (47,485) $ 674,634 Expenses: Operating costs — 256,024 176,189 (47,485) 384,728 Depreciation, depletion, and amortization 7,707 220,203 47,663 — 275,573 Impairments — 622,676 3,040 — 625,716 General and administrative — 38,246 — — 38,246 (Gain) loss on disposition of assets (11) 3,673 (160) — 3,502 Total operating costs 7,696 1,140,822 226,732 (47,485) 1,327,765 Income (loss) from operations (7,696) (646,642) 1,207 — (653,131) Interest, net (35,466) — (1,546) — (37,012) Gain on derivatives 4,225 — — — 4,225 Other, net 786 (1,086) 64 — (236) Loss before income taxes (38,151) (647,728) (275) — (686,154) Income tax expense (benefit) 7,238 (139,564) — — (132,326) Equity in net earnings from investment in subsidiaries, net of taxes (508,439) — — 508,439 — Net loss (553,828) (508,164) (275) 508,439 (553,828) Less: net income attributable to non-controlling interest 51 — 51 (51) 51 Net loss attributable to Unit Corporation $ (553,879) $ (508,164) $ (326) $ 508,490 $ (553,879) |
Condensed Consolidating Statement of Comprehensive Income (Loss) | Condensed Consolidating Statements of Comprehensive Income (Loss) Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (890,624) $ (1,108,875) $ (132,246) $ 1,241,121 $ (890,624) Other comprehensive loss, net of taxes: Unrealized gain on securities, net of tax of $0 — — — — — Comprehensive loss (890,624) (1,108,875) (132,246) 1,241,121 (890,624) Less: Comprehensive income attributable to non-controlling interests 40,388 — 40,388 (40,388) 40,388 Comprehensive loss attributable to Unit Corporation $ (931,012) $ (1,108,875) $ (172,634) $ 1,281,509 $ (931,012) Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) Net loss $ (553,828) $ (508,164) $ (275) $ 508,439 $ (553,828) Other comprehensive loss, net of taxes: Reclassification adjustment for write-down of securities, net of tax $(47) — 481 — — 481 Comprehensive loss (553,828) (507,683) (275) 508,439 (553,347) Less: Comprehensive income attributable to non-controlling interests 51 — 51 (51) 51 Comprehensive loss attributable to Unit Corporation $ (553,879) $ (507,683) $ (326) $ 508,490 $ (553,398) |
Condensed Consolidating Statements of Cash Flows | Predecessor Eight Months Ended August 31, 2020 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (207,593) $ 82,769 $ 32,922 $ 136,858 $ 44,956 INVESTING ACTIVITIES: Capital expenditures (986) (14,585) (10,204) — (25,775) Producing properties and other acquisitions — (382) — — (382) Proceeds from disposition of assets 1,169 4,772 77 — 6,018 Net cash provided by (used in) investing activities 183 (10,195) (10,127) — (20,139) FINANCING ACTIVITIES: Borrowings under credit agreement, including borrowings under DIP credit facility 55,300 — 32,100 — 87,400 Payments under credit agreement (31,500) — (32,600) — (64,100) DIP financing costs (990) — — — (990) Exit facility financing costs (3,225) — — — (3,225) Intercompany borrowings (advances), net 210,398 (72,642) (898) (136,858) — Payments on finance leases — — (2,757) — (2,757) Employee taxes paid by withholding shares (43) — — — (43) Bank overdrafts (7,269) — (1,464) — (8,733) Net cash provided by (used in) financing activities 222,671 (72,642) (5,619) (136,858) 7,552 Net increase (decrease) in cash and cash equivalents 15,261 (68) 17,176 — 32,369 Cash and cash equivalents, beginning of period 503 68 — — 571 Cash and cash equivalents, end of period $ 15,764 $ — $ 17,176 $ — $ 32,940 Predecessor Twelve Months Ended December 31, 2019 Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated (In thousands) OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (9,681) $ 217,883 $ 48,856 $ 12,338 $ 269,396 INVESTING ACTIVITIES: Capital expenditures 65 (355,258) (51,472) — (406,665) Producing properties and other acquisitions — (3,653) — — (3,653) Other acquisitions — — (16,109) — (16,109) Proceeds from disposition of assets 11 31,153 700 — 31,864 Net cash provided by (used in) investing activities 76 (327,758) (66,881) — (394,563) FINANCING ACTIVITIES: Borrowings under credit agreement 400,600 — 92,900 — 493,500 Payments under credit agreement (292,400) — (76,400) — (368,800) Intercompany borrowings (advances), net (97,455) 109,735 58 (12,338) — Payments on finance leases — — (4,001) — (4,001) Employee taxes paid by withholding shares (4,158) — — — (4,158) Distributions to non-controlling interest 919 — (1,837) — (918) Bank overdrafts 2,199 — 1,464 — 3,663 Net cash provided by (used in) financing activities 9,705 109,735 12,184 (12,338) 119,286 Net increase (decrease) in cash and cash equivalents 100 (140) (5,841) — (5,881) Cash and cash equivalents, beginning of period 403 208 5,841 — 6,452 Cash and cash equivalents, end of period $ 503 $ 68 $ — $ — $ 571 |
Supplemental Oil And Gas Disc_2
Supplemental Oil And Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
Supplemental Oil and Gas Disclosures [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | The capitalized costs at year end were as follows: Successor Predecessor 2020 2019 (In thousands) Proved properties $ 238,581 $ 6,341,582 Unproved properties (wells in progress) 1,591 252,874 240,172 6,594,456 Accumulated depreciation, depletion, amortization, and impairment (40,806) (5,846,177) Net capitalized costs $ 199,366 $ 748,279 |
Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized [Table Text Block] | The following table sets forth costs incurred related to our oil and natural gas activities for the periods indicated: Successor Predecessor Period Period For the Year Ended (In thousands) Unproved properties acquired $ 26 $ 2,373 $ 34,668 Proved properties acquired — 382 3,653 Exploration — — 16,480 Development 3,992 6,440 211,443 Asset retirement obligation (1,702) (29,189) 76 Total costs incurred $ 2,316 $ (19,994) $ 266,320 |
Results Of Operations For Producing Activities [Table Text Block] | The results of operations for producing activities are as follows: Successor Predecessor Period Period For the Year Ended (In thousands) Revenues $ 55,272 $ 96,033 $ 314,925 Production costs (20,510) (46,633) (116,051) Depreciation, depletion, amortization, and impairment (40,840) (461,901) (727,529) (6,078) (412,501) (528,655) Income tax (expense) benefit 128 6,698 101,952 Results of operations for producing activities (excluding corporate overhead and financing costs) $ (5,950) $ (405,803) $ (426,703) |
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities [Table Text Block] | Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows: Oil Bbls NGLs Bbls Natural Gas Mcf Total MBoe (In thousands) 2019 Proved developed and undeveloped reserves: Beginning of year 22,558 47,796 535,963 159,681 Revision of previous estimates (1) (8,263) (20,961) (234,852) (68,366) Extensions and discoveries (1) 703 845 8,798 3,015 Infill reserves in existing proved fields 271 434 4,806 1,506 Purchases of minerals in place 183 101 1,316 503 Production (3,208) (4,773) (53,064) (16,825) Sales (48) (412) (42,780) (7,590) Net proved reserves at December 31, 2019 12,196 23,030 220,187 71,924 Proved developed reserves, December 31, 2019 12,196 23,030 220,187 71,924 Proved undeveloped reserves, December 31, 2019 — — — — 2020 Proved developed and undeveloped reserves: Beginning of year 12,196 23,030 220,187 71,924 Revision of previous estimates (1,909) (4,477) (38,901) (12,870) Extensions and discoveries 8 13 110 39 Infill reserves in existing proved fields 97 66 452 238 Purchases of minerals in place 62 20 172 112 Production (2,186) (3,444) (37,567) (11,891) Sales (1) — (62) (11) Net proved reserves at December 31, 2020 8,267 15,208 144,391 47,541 Proved developed reserves, December 31, 2020 8,267 15,208 144,391 47,541 Proved undeveloped reserves, December 31, 2020 — — — — _________________________ 1. Revisions of previous estimates and extensions and discoveries decreased primarily due to the removal of proved undeveloped reserves due to uncertainty regarding our ability to finance the development of our proved undeveloped reserves over a five-year period and from lower commodity prices. |
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure [Table Text Block] | The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows: Successor Predecessor 2020 2019 (In thousands) Future cash flows $ 698,685 $ 1,386,777 Future production costs (416,095) (698,357) Future development costs — — Future income tax expenses (39) (321) Future net cash flows 282,551 688,099 10% annual discount for estimated timing of cash flows (89,530) (226,390) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 193,021 $ 461,709 |
Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Table Text Block] | The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: 2020 2019 Sales and transfers of oil and natural gas produced, net of production costs $ (84,163) $ (200,233) Net changes in prices and production costs (165,978) (508,066) Revisions in quantity estimates and changes in production timing (50,979) (338,994) Extensions, discoveries, and improved recovery, less related costs 2,827 53,123 Changes in estimated future development costs — 311,190 Previously estimated cost incurred during the period — 64,362 Purchases of minerals in place 852 6,416 Sales of minerals in place (46) (25,813) Accretion of discount 46,203 110,571 Net change in income taxes 282 121,708 Changes in timing and other (17,686) (116,233) Net change (268,688) (521,969) Beginning of year 461,709 983,678 End of year $ 193,021 $ 461,709 |
Schedule II - Valuation And Q_2
Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Tables) | 12 Months Ended |
Dec. 31, 2020 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Summary of Valuation Allowance [Table Text Block] | Allowance for Doubtful Accounts: Description Balance at Beginning of Period Additions Deductions & Net Write-Offs Balance at End of Period (In thousands) Year ended December 31, 2020 $ 2,332 $ 3,155 $ (1,704) $ 3,783 Year ended December 31, 2019 $ 2,531 $ 527 $ (726) $ 2,332 |
Emergence from Voluntary Reor_2
Emergence from Voluntary Reorganization Under Chapter 11 (Details) | Feb. 11, 2021USD ($) | Dec. 21, 2020USD ($)shares | Sep. 03, 2020 | Aug. 06, 2020 | May 22, 2020 | May 15, 2020USD ($) | Aug. 31, 2020USD ($) | Dec. 31, 2020$ / shares | Sep. 01, 2020$ / sharesshares | Dec. 31, 2019$ / shares |
Bankruptcy Proceedings, Date Petition for Bankruptcy Filed | May 22, 2020 | |||||||||
Bankruptcy Proceedings, Court Where Petition Was Filed | United States Bankruptcy Court for the Southern District of Texas, Houston Division | |||||||||
Plan of Reorganization, Date Plan Confirmed | Aug. 6, 2020 | |||||||||
Plan of Reorganization, Date Plan is Effective | Sep. 3, 2020 | |||||||||
Plan of Reorganization, Terms of Plan | Following emergence, we implemented the Plan as follows:•Each lender under the (i) the Unit credit agreement, and (ii) the DIP Credit Agreement received (or was entitled to receive) its pro rata share of revolving loans, term loans, and letter of credit participations under the Exit Credit Agreement, in exchange for the lender’s allowed claims under the Unit credit agreement or DIP Credit Agreement; •Each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described below); •The company issued a total of 12.0 million shares of New Common Stock at a par value of $0.01 per share to be subsequently distributed in accordance with the Plan; •Each holder of the Notes received its pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim;•Each holder of an allowed general unsecured claim against Unit or UPC was entitled to receive its pro rata share of New Common Stock based on equity allocations at each of Unit and UPC, respectively; •A disputed claims reserve was established for distribution of New Common Stock on allowance of certain disputed general unsecured claims;•Each holder of an allowed general unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA received payment or will receive payment in full for that claim in the ordinary course of business; and•Each retained or former employee with a claim for vested severance benefits, who opted into a settlement, received or will receive cash payment(s) for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims. | |||||||||
Warrants and Rights Outstanding, Maturity Date | Sep. 3, 2027 | |||||||||
Stock and Warrants Issued During Period, Value, Preferred Stock and Warrants | $ | $ 1,800,000 | |||||||||
Class of Warrant or Right, Unissued | shares | 37,000 | |||||||||
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | $ | $ 12,400,000 | |||||||||
Debt Instrument, Periodic Payment, Interest | $ | $ 21,500,000 | |||||||||
Shares, Issued | shares | 12,000,000 | |||||||||
Common stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.20 | |||||||
Subsequent Event | ||||||||||
Stock and Warrants Issued During Period, Value, Preferred Stock and Warrants | $ | $ 43,000 | |||||||||
Common Stock | ||||||||||
Percentage of New Common Shares of the Reorganized Company | 12.50% | |||||||||
DIP credit facility [Member] | ||||||||||
Percentage of Equity Allocated to Holders of Debtors | 5.00% | |||||||||
Minimum | ||||||||||
Substantial Stockholder Percentage | 0.0475 | |||||||||
Notes Holders [Member] | ||||||||||
Common Stock, Shares, Outstanding | shares | 10,500,000 | |||||||||
Disputed Claims Reserve [Member] | ||||||||||
Common Stock, Shares, Outstanding | shares | 900,000 |
Fresh Start Accounting (Schedul
Fresh Start Accounting (Schedule of Reconciliation of Enterprise Value to Fair Value of Successor Equity (Details) $ in Thousands | Sep. 01, 2020USD ($) |
Reorganizations [Abstract] | |
Enterprise value | $ 559,205 |
Less: Fair value of noncontrolling interest | (242,200) |
Enterprise value of Unit interests | 317,005 |
Plus: Cash and cash equivalents | 25,482 |
Plus: Restricted cash | 7,458 |
Less: Fair value of capital leases | (4,622) |
Less: Fair value of debt (including the fair value of current debt) | (148,000) |
Fair value of Successor equity | $ 197,323 |
Fresh Start Accounting (Sched_2
Fresh Start Accounting (Schedule of Reconciliation of Enterprise Value to the Reorganization Value (Details) $ in Thousands | Sep. 01, 2020USD ($) |
Reorganizations [Abstract] | |
Enterprise value | $ 559,205 |
Plus: Cash and cash equivalents | 25,482 |
Plus: Restricted cash | 7,458 |
Plus: Current liabilities (excluding the fair value of capital leases and current debt) | 86,897 |
Plus: Long-term asset retirement obligation | 22,415 |
Plus: Other long-term liabilities (excluding long-term asset retirement obligation) | 24,886 |
Reorganization value of Successor assets | $ 726,343 |
Fresh Start Accounting (Sched_3
Fresh Start Accounting (Schedule of Fresh Start Adjustments) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | |
Fresh-Start Adjustment [Line Items] | ||||
Preconfirmation, Cash and Cash Equivalents | $ 32,280 | |||
Plus: Cash and cash equivalents | $ 25,482 | |||
Preconfirmation, Restricted Cash and Cash Equivalents, Current | 0 | |||
Plus: Restricted cash | 7,458 | |||
Preconfirmation, Receivables, Net | 50,621 | |||
Postconfirmation, Receivables, Net | 50,621 | |||
Preconfirmation, Inventories | 64 | |||
Postconfirmation, Inventories | 0 | |||
Preconfirmation, Deferred Income Tax Assets, Current | 850 | |||
Postconfirmation, Deferred Income Tax Assets, Current | 850 | |||
Preconfirmation, Prepaid and Other Current Assets | 13,692 | |||
Postconfirmation, Prepaid and Other Current Assets | 19,084 | |||
Preconfirmation, Current Assets | 97,507 | |||
Postconfirmation, Current Assets | 103,495 | |||
Preconfirmation, Capitalized Costs, Proved Properties | 6,539,816 | |||
Postconfirmation, Capitalized Costs, Proved Properties | 238,284 | |||
Preconfirmation, Capitalized Costs of Unproved Properties | 30,205 | |||
Postconfirmation, Capitalized Costs of Unproved Properties | 0 | |||
Preconfirmation, Capitalized Costs, Support Equipment and Facilities | 1,285,024 | |||
Postconfirmation, Capitalized Costs, Support Equipment and Facilities | 63,458 | |||
Preconfirmation, Natural gas gathering systems and treating plants | 833,788 | |||
Postconfirmation, Natural gas gathering systems and treating plants | 250,098 | |||
Preconfirmation, Saltwater disposal systems | 43,541 | |||
Postconfirmation, Saltwater disposal systems | 0 | |||
Preconfirmation, Land | 59,080 | |||
Postconfirmation, Land | 32,635 | |||
Preconfirmation, Equipment | 15,577 | |||
Postconfirmation, Equipment | 3,314 | |||
Preconfirmation, Other Property and Equipment | 57,427 | |||
Postconfirmation, Other Property and Equipment | 9,958 | |||
Preconfirmation, Property, plant and equipment, gross | 8,864,458 | |||
Postconfirmation, Property, plant, and equipment, gross | 597,747 | |||
Preconfirmation, Accumulated Depreciation and Amortization | 7,923,868 | |||
Postconfirmation, Accumulated Depreciation and Amortization | 0 | |||
Preconfirmation, Property and Equipment, Net | 940,590 | |||
Postconfirmation, Property and Equipment, Net | 597,747 | |||
Preconfirmation, operating lease, right-of-use asset | 7,476 | |||
Postconfirmation, operating lease, right-of-use asset | 6,817 | |||
Preconfirmation, Other Assets, Noncurrent | 24,666 | |||
Postconfirmation, Other Assets | 18,284 | |||
Preconfirmation, Other Assets | 1,070,239 | |||
Postconfirmation, Assets | 726,343 | |||
Preconfirmation, Accounts Payable | 27,354 | |||
Postconfirmation, Accounts Payable | 33,736 | |||
Preconfirmation, Accrued Liabilities | 36,990 | |||
Postconfirmation, Accrued Liabilities | 32,875 | |||
Preconfirmation, Operating lease, liability, current | 4,643 | |||
Postconfirmation, Operating lease, liability, current | 3,974 | |||
Preconfirmation, Current Maturities of Long-term Debt | 124,000 | |||
Postconfirmation, Current Maturities of Long-term Debt | 400 | |||
Preconfirmation, Current derivative liabilities | 5,089 | |||
Postconfirmation, Derivative liability, current | 5,089 | |||
Preconfirmation, Warrant liability | 0 | |||
Postconfirmation, Warrant liability | 885 | |||
Preconfirmation, Other Current Liabilities | 11,201 | |||
Postconfirmation, Other Current Liabilities | 14,960 | |||
Preconfirmation, Current Liabilities | 209,277 | |||
Postconfirmation, Current Liabilities | 91,919 | |||
Preconfirmation, Long-term Debt | 16,000 | |||
Postconfirmation, Postconfirmation Credit Facility | 147,600 | |||
Preconfirmation, Derivative liability, Noncurrent | 766 | |||
Postconfirmation, Derivative Liability, Noncurrent | 766 | |||
Preconfirmation, Operating lease, liability, Noncurrent | 2,760 | |||
Postconfirmation, Operating lease, liability, Noncurrent | 2,771 | |||
Preconfirmation, Noncurrent Other Obligations | 61,393 | |||
Postconfirmation, Noncurrent Other Obligations | 43,764 | |||
Preconfirmation, Liabilities Subject to Compromise | 762,215 | |||
Postconfirmation, Liabilities Subject to Compromise | 0 | |||
Preconfirmation, Deferred Income Tax Liabilities, Noncurrent | 4,466 | |||
Postconfirmation, Deferred Income Tax Liabilities, Noncurrent | 0 | |||
Preconfirmation, Preferred Stock | 0 | |||
Preconfirmation, Common Stock | 10,704 | |||
Preconfirmation, Additional Paid-in Capital | 650,153 | |||
Postconfirmation, Preferred Stock | 0 | |||
Postconfirmation, Common Stock | 120 | |||
Postconfirmation, Additional Paid-in Capital | 197,203 | |||
Preconfirmation, Retained Earnings (Deficit) | (818,679) | |||
Postconfirmation, Retained Earnings (Deficit) | 0 | |||
Preconfirmation, Stockholders' Equity Attributable to Parent | (157,822) | |||
Fair value of Successor equity | 197,323 | |||
Preconfirmation, Stockholders' Equity Attributable to Noncontrolling Interest | 171,184 | |||
Postconfirmation, Stockholders' Equity Attributable to Noncontrolling Interest | 242,200 | |||
Preconfirmation, Stockholders' Equity | 13,362 | |||
Postconfirmation, Stockholders' Equity | 439,523 | |||
Preconfirmation, Liabilities and Stockholders' Equity | $ 1,070,239 | |||
Postconfirmation, Liabilities and Stockholders' Equity | 726,343 | |||
Operating loss carryforwards | $ 409,100 | 726,400 | ||
Operating loss carryforwards subject to expiration | $ 223,000 | 584,200 | ||
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration | 142,200 | |||
Reorganization Adjustments | ||||
Fresh-Start Adjustment [Line Items] | ||||
Changes in cash and cash equivalents | [1],[2] | (6,798) | ||
Fresh-Start Adjustment, Increase (Decrease), Restricted Cash and Cash Equivalents, Current | [1],[3] | 7,458 | ||
Fresh-Start Adjustment, Increase (Decrease), Receivables, Net | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Inventories | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Assets, Current | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Prepaid and Other Current Assets | [1],[4] | 6,382 | ||
Fresh-Start Adjustment, Increase (Decrease), Current Assets | [1] | 7,042 | ||
Fresh Start Adjustment, Increase (Decrease), Capitalized Costs, Proved Properties | [1] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Capitalized Costs of Unproved Properties | [1] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Capitalized Costs, Support Equipment and Facilities | [1] | 0 | ||
Fresh Start Adjustments, Increase (Decrease) Natural gas gathering systems and treating plants | [1] | 0 | ||
Fresh Start Adjustments, Increase (Decrease) Saltwater disposal systems | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Land | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Equipment | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Other Property and Equipment | [1] | 0 | ||
Fresh Start Adjustments, Increase (Decrease) Property, plant, and equipment, gross | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Accumulated Depreciation and Amortization | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Property and Equipment, Net | [1] | 0 | ||
Fresh Start Accounting, Increase (Decrease) Operating lease, right-of-use asset | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Other Assets | [1],[4] | (6,382) | ||
Fresh-Start Adjustment, Increase (Decrease), Assets | [1] | 660 | ||
Fresh-Start Adjustment, Increase (Decrease), Accounts Payable | [1],[4] | 6,382 | ||
Fresh-Start Adjustment, Increase (Decrease), Accrued Liabilities | [1],[5] | (4,115) | ||
Fresh Start Adjustment, Increase/(Decrease), Operating Lease Liability, Current | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Current Maturities of Long-term Debt | [1],[6] | (123,600) | ||
Fresh Start Adjustment, Increase (Decrease), Derivative liability, current | [1] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Warrant liability | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Other Current Liabilities | [1],[7] | 3,743 | ||
Fresh-Start Adjustment, Increase (Decrease), Current Liabilities | [1] | (117,590) | ||
Fresh-Start Adjustment, Increase (Decrease), Postconfirmation Credit Facility | [1],[6] | 131,600 | ||
Fresh Start Adjustment, Increase (Decrease), Derivative Liability, Noncurrent | [1] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Operating lease, liability, noncurrent | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Noncurrent Other Obligations | [1],[4],[7] | (3,220) | ||
Fresh-Start Adjustment, Increase (Decrease), Liabilities Subject to Compromise | [1],[8] | (762,215) | ||
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent | [1] | 0 | ||
Preconfirmation, Preferred Stock | [1] | 0 | ||
Preconfirmation, Common Stock | [1],[9] | (10,704) | ||
Preconfirmation, Additional Paid-in Capital | [1],[9] | (650,153) | ||
Fresh-Start Adjustment, Increase (Decrease), Preferred Stock | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Common Stock | [1],[8] | 120 | ||
Fresh-Start Adjustment, Increase (Decrease), Additional Paid-in Capital | [1],[8] | 197,203 | ||
Fresh-Start Adjustment, Increase (Decrease), Retained Earnings (Deficit) | [1],[10] | 1,215,619 | ||
Fresh Start Adjustment, Increase (Decrease) Stockholders' Equity Attributable to Parent | [1] | 752,085 | ||
Fresh Start Adjustment, Increase (Decrease) Stockholders' Equity Attributable to Noncontrolling Interest | [1] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Stockholders' Equity | [1] | 752,085 | ||
Fresh-Start Adjustment, Increase (Decrease), Liabilities and Stockholders' Equity | [1] | 660 | ||
Fresh start adjustments | ||||
Fresh-Start Adjustment [Line Items] | ||||
Changes in cash and cash equivalents | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Restricted Cash and Cash Equivalents, Current | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Receivables, Net | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Inventories | [11] | (64) | ||
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Assets, Current | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Prepaid and Other Current Assets | [12] | (990) | ||
Fresh-Start Adjustment, Increase (Decrease), Current Assets | (1,054) | |||
Fresh Start Adjustment, Increase (Decrease), Capitalized Costs, Proved Properties | [13] | (6,301,532) | ||
Fresh Start Adjustment, Increase (Decrease) Capitalized Costs of Unproved Properties | [13] | (30,205) | ||
Fresh Start Adjustment, Increase (Decrease) Capitalized Costs, Support Equipment and Facilities | [14] | (1,221,566) | ||
Fresh Start Adjustments, Increase (Decrease) Natural gas gathering systems and treating plants | [14] | (583,690) | ||
Fresh Start Adjustments, Increase (Decrease) Saltwater disposal systems | [14] | (43,541) | ||
Fresh-Start Adjustment, Increase (Decrease), Land | [14] | (26,445) | ||
Fresh-Start Adjustment, Increase (Decrease), Equipment | [14] | (12,263) | ||
Fresh-Start Adjustment, Increase (Decrease), Other Property and Equipment | [14] | (47,469) | ||
Fresh Start Adjustments, Increase (Decrease) Property, plant, and equipment, gross | (8,266,711) | |||
Fresh-Start Adjustment, Increase (Decrease), Accumulated Depreciation and Amortization | [13],[14] | (7,923,868) | ||
Fresh-Start Adjustment, Increase (Decrease), Property and Equipment, Net | (342,843) | |||
Fresh Start Accounting, Increase (Decrease) Operating lease, right-of-use asset | [15] | (659) | ||
Fresh-Start Adjustment, Increase (Decrease), Other Assets | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Assets | (344,556) | |||
Fresh-Start Adjustment, Increase (Decrease), Accounts Payable | [16] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Accrued Liabilities | [16] | 0 | ||
Fresh Start Adjustment, Increase/(Decrease), Operating Lease Liability, Current | [15],[16] | (669) | ||
Fresh-Start Adjustment, Increase (Decrease), Current Maturities of Long-term Debt | [16] | 0 | ||
Fresh Start Adjustment, Increase (Decrease), Derivative liability, current | [16] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Warrant liability | [16],[17] | 885 | ||
Fresh-Start Adjustment, Increase (Decrease), Other Current Liabilities | [16],[18] | 16 | ||
Fresh-Start Adjustment, Increase (Decrease), Current Liabilities | [16] | 232 | ||
Fresh-Start Adjustment, Increase (Decrease), Postconfirmation Credit Facility | [16] | 0 | ||
Fresh Start Adjustment, Increase (Decrease), Derivative Liability, Noncurrent | [16] | 0 | ||
Fresh Start Adjustment, Increase (Decrease) Operating lease, liability, noncurrent | [15],[16] | 11 | ||
Fresh-Start Adjustment, Increase (Decrease), Noncurrent Other Obligations | [16],[18] | (14,409) | ||
Fresh-Start Adjustment, Increase (Decrease), Liabilities Subject to Compromise | [16] | 0 | ||
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent | [16],[19] | (4,466) | ||
Preconfirmation, Preferred Stock | 0 | |||
Preconfirmation, Common Stock | 0 | |||
Preconfirmation, Additional Paid-in Capital | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Preferred Stock | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Common Stock | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Additional Paid-in Capital | 0 | |||
Fresh-Start Adjustment, Increase (Decrease), Retained Earnings (Deficit) | [20] | (396,940) | ||
Fresh Start Adjustment, Increase (Decrease) Stockholders' Equity Attributable to Parent | (396,940) | |||
Fresh Start Adjustment, Increase (Decrease) Stockholders' Equity Attributable to Noncontrolling Interest | [21] | 71,016 | ||
Fresh-Start Adjustment, Increase (Decrease), Stockholders' Equity | (325,924) | |||
Fresh-Start Adjustment, Increase (Decrease), Liabilities and Stockholders' Equity | $ (344,556) | |||
[1] | Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes. | |||
[2] | The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands): Funding of the professional fees escrow account $ (7,458) Proceeds from Exit credit facility 8,000 Payment of debt issuance costs on the Exit credit facility (3,225) Payment of professional fees (3,943) Payment of accrued interest payable under the Predecessor credit facility (172) Changes in cash and cash equivalents $ (6,798) | |||
[3] | Represents the reserve for professional fee escrow of $7.5 million. | |||
[4] | Represents the reclassification of other long-term assets related to deferred compensation to prepaid expenses and other assets as the deferred compensation payout must be paid within 12 months from the date of emergence under the Plan. Simultaneously, the current portion of deferred compensation liability was reclassified from other long-term liabilities to accounts payable. | |||
[5] | Represents the payment of the DIP facility interest of $0.2 million and professional fees for $3.9 million | |||
[6] | Represents the transition of the DIP Credit Agreement and the Predecessor Credit Agreement of $124.0 million into the Exit Facility and issuing an additional $8.0 million of borrowings under the Exit Credit Agreement. | |||
[7] | Represents the reclassification of the short-term portion of the separation benefit liabilities from non-current to current liabilities which was offset by the increase in non-current portion of liabilities. | |||
[8] | Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands): Liabilities subject to compromise before the Effective Date: 6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date) $ 672,369 Accounts payable 1,179 Employee separation benefit plan obligations 23,394 Litigation settlements 45,000 Royalty suspense accounts payable 20,273 Total liabilities subject to compromise 762,215 Separation settlement treatment (6,905) Successor Common Stock and APIC (1) issued to allowed claim holders (175,521) Successor Common Stock and APIC for disputed claims reserve (11,936) Gain on settlement of liabilities subject to compromise $ 567,853 (1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise. | |||
[9] | Represents the cancellation of Old Common Stock. | |||
[10] | Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above. | |||
[11] | Represents the reclassification of materials and supplies to proved properties. | |||
[12] | Represents the write off of the Predecessor's unamortized debt fees related to the DIP facility. | |||
[13] | Reflects a decrease of oil and natural gas properties, net, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Proved properties $ 238,284 $ 6,539,816 Unproved properties — 30,205 238,284 6,570,021 Less accumulated depletion, amortization, and impairment — (6,305,113) $ 238,284 $ 264,908 | |||
[14] | Reflects a decrease in fair value of drilling equipment, gas gathering and processing equipment, saltwater disposal systems, land and building, transportation equipment, and other property and equipment and the elimination of accumulated depreciation, based on the methodologies discussed above. The following table summarizes the components of other property and equipment as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (In thousands) Drilling equipment $ 63,458 $ 1,285,024 Gas gathering and processing equipment 250,098 833,788 Saltwater disposal systems — 43,541 Land and building 32,635 59,080 Transportation equipment 3,314 15,577 Other 9,958 57,427 359,463 2,294,437 Less accumulated depreciation and impairment — (1,618,754) $ 359,463 $ 675,683 | |||
[15] | Reflects the valuation adjustments to the company’s right of use assets, current operating lease liability, and operating lease liability, adjusted for fair value of favorable and unfavorable lease terms, and the revised incremental borrowing rates of the Successor. | |||
[16] | Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below. | |||
[17] | Represents the liability for the Warrants using a Black-Scholes-Merton model which uses various market-based inputs including: stock prices, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield. | |||
[18] | Represents the reclassification of the short-term portion of ARO from non-current liabilities to current and the fair value adjustment, which was determined using our fresh start updates to these obligations, including the application of the Successor's credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of well plugging activity, and resetting all ARO to a single layer. | |||
[19] | Represents the adjustments to deferred tax liability as a result of the cumulative tax impact of the fresh start adjustments. The significant revisions to the carrying value of our assets and liabilities because of applying fresh start accounting resulted in the company increasing its overall net deferred tax asset position on emergence from bankruptcy. Besides the changes in book value, the company has as of the Effective Date, approximately $726.4 million of net operating losses (NOLs) carried forward to offset taxable income in the future years. Approximately $584.2 million of this NOL will expire commencing in fiscal 2021 through 2037. The NOLs of approximately $142.2 million from years ended after December 31, 2017 have an indefinite carryforward period. The amount of these NOLs which is available to offset future income may be severely limited due to change-in-control tax provisions. Because of our history of operating losses and the uncertainty surrounding the realization of the deferred tax assets in future years, we have determined that it is more likely than not that the deferred tax assets will not be realized in future periods. Accordingly, we recorded a 100% valuation allowance against our net deferred tax assets. | |||
[20] | Represents the cumulative impact of the fresh start accounting adjustments discussed above. | |||
[21] | The valuation of the non-controlling interest was calculated by taking an income-based approach in valuing Superior. The value of the non-controlling interest was then determined based on a market-based approach for similar type investments, given the contractual rights of the related parties. |
Fresh Start Accounting (Sources
Fresh Start Accounting (Sources and Uses of Cash) (Details) - Reorganization Adjustments $ in Thousands | Sep. 01, 2020USD ($) | |
Fresh-Start Adjustment [Line Items] | ||
Funding of the professional fees escrow account | $ (7,458) | |
Proceeds from Exit credit facility | 8,000 | |
Payment of debt issuance costs on the Exit credit facility | (3,225) | |
Payment of professional fees | (3,943) | |
Payment of accrued interest payable under the Predecessor credit facility | (172) | |
Changes in cash and cash equivalents | $ (6,798) | [1],[2] |
[1] | Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes. | |
[2] | The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands): Funding of the professional fees escrow account $ (7,458) Proceeds from Exit credit facility 8,000 Payment of debt issuance costs on the Exit credit facility (3,225) Payment of professional fees (3,943) Payment of accrued interest payable under the Predecessor credit facility (172) Changes in cash and cash equivalents $ (6,798) |
Fresh Start Accounting (Gain on
Fresh Start Accounting (Gain on Settlement of Liabilities Subject to Compromise) (Details) - USD ($) $ in Thousands | 2 Months Ended | 4 Months Ended | 8 Months Ended | ||
Aug. 31, 2020 | Dec. 31, 2020 | Aug. 31, 2020 | Sep. 01, 2020 | Dec. 31, 2019 | |
Fresh-Start Adjustment [Line Items] | |||||
6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date) | $ 672,369 | ||||
Accounts payable | 1,179 | ||||
Employee separation benefit plan obligations | 23,394 | ||||
Litigation settlements | $ 2,070 | 45,000 | $ 0 | ||
Royalty suspense accounts payable | 20,273 | ||||
Total liabilities subject to compromise | 762,215 | ||||
Separation settlement treatment | (6,905) | ||||
Common Stock, Value, Issued | (120) | $ (10,591) | |||
Gain on settlement of liabilities subject to compromise | $ 567,853 | 0 | $ 567,853 | ||
5% equity facility | $ 9,900 | $ 0 | $ 9,866 | ||
Allowed claim holders | |||||
Fresh-Start Adjustment [Line Items] | |||||
Common Stock, Value, Issued | (175,521) | ||||
Disputed Claims Reserve [Member] | |||||
Fresh-Start Adjustment [Line Items] | |||||
Common Stock, Value, Issued | $ (11,936) |
Fresh Start Accounting (Oil and
Fresh Start Accounting (Oil and Gas Properties Schedule) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 |
Proved properties | $ 238,581 | $ 238,284 | $ 6,539,816 | $ 6,341,582 |
Unproved properties not being amortized | 1,591 | 0 | 30,205 | 252,874 |
Property, plant and equipment, gross, total | 600,989 | 8,931,355 | ||
Less accumulated depletion, amortization, and impairment | (54,189) | (6,978,669) | ||
Net property and equipment | $ 546,800 | $ 1,952,686 | ||
Oil and Natural Gas | ||||
Property, plant and equipment, gross, total | 238,284 | 6,570,021 | ||
Less accumulated depletion, amortization, and impairment | 0 | (6,305,113) | ||
Net property and equipment | $ 238,284 | $ 264,908 |
Fresh Start Accounting (Other P
Fresh Start Accounting (Other Property Schedule) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 |
Drilling equipment | $ 63,687 | $ 63,458 | $ 1,285,024 | $ 1,295,713 |
Gas gathering and processing equipment | 251,404 | 250,098 | 833,788 | 824,699 |
Saltwater disposal systems | 0 | 0 | 43,541 | 69,692 |
Land and building | 32,635 | 32,635 | 59,080 | 59,080 |
Transportation equipment | 3,130 | 3,314 | 15,577 | 29,723 |
Other | 9,961 | 9,958 | 57,427 | 57,992 |
Property, plant and equipment, gross, total | 600,989 | 8,931,355 | ||
Less accumulated depletion, amortization, and impairment | (54,189) | (6,978,669) | ||
Net property and equipment | $ 546,800 | $ 1,952,686 | ||
Non Oil and Natural Gas | ||||
Property, plant and equipment, gross, total | 359,463 | 2,294,437 | ||
Less accumulated depletion, amortization, and impairment | 0 | (1,618,754) | ||
Net property and equipment | $ 359,463 | $ 675,683 |
Fresh Start Accounting (Sched_4
Fresh Start Accounting (Schedule of Reorganization Items) (Details) - USD ($) $ in Thousands | 2 Months Ended | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Aug. 31, 2020 | Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Reorganizations [Abstract] | ||||
Gains on settlement of liabilities subject to compromise | $ (567,853) | $ 0 | $ (567,853) | |
Fresh start accounting adjustments | 0 | 401,406 | ||
Legal and professional fees and expenses | 2,273 | 15,745 | ||
Acceleration of Predecessor stock compensation expense | 0 | 1,431 | ||
Exit Facility fees | 0 | 3,225 | ||
5% equity facility | $ 9,900 | 0 | 9,866 | |
Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021 | 0 | 2,205 | ||
Total reorganization items, net | $ 2,273 | $ (133,975) | $ 0 |
Reorganizations (Details)
Reorganizations (Details) - USD ($) $ in Thousands | Sep. 03, 2020 | Sep. 01, 2020 |
Enterprise value | $ 559,205 | |
Enterprise value of Unit interests | 317,005 | |
Reorganization value of Successor assets | 726,343 | |
Oil and Natural Gas | ||
Reorganization Value, Methodology and Assumptions | Our oil and natural gas properties are accounted for under the full cost accounting method. We determined the fair value of our oil and gas properties based on the anticipated cash flows associated with our proved reserves and discounted those cash flows using a weighted average cost of capital rate of 13.5%. The discount rate is commonly based on empirical studies of investment rates of return of publicly traded equity securities with investment return and risk characteristics similar to the subject company, which follows a market-based approach. Weighted average commodity prices used in determining the fair value of oil and natural gas properties were $48.98 per barrel of oil, $2.68 per million cubic feet of natural gas and $18.51 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices. Our unproved acreage was determined to have no value due to the capital constraints contained in our debt agreement along with our plans to not drill in our proved reserves cash flows. Our salt water disposal assets were included in the cash flows of the proved reserves forecast, therefore, those values are included in the total value of our proved properties. | |
Drilling Equipment | ||
Reorganization Value, Methodology and Assumptions | The value of our drilling rigs in operation (approximately $37.0 million) was estimated using an income-based approach using discounted free cash flows over the remaining useful lives of the drilling rigs. Anticipated cash flows associated with operating drilling rigs were discounted using a weighted average cost of capital rate of 13.8% for five years with a terminal value at the conclusion of the forecast period. The fair value of our non-operating drilling rigs, and other related drilling equipment (approximately $26.5 million), was valued using a market-based approach with varying ranges of economic obsolescence rates to adjust for the impact of the oil and gas downturn. | |
Land and Building | ||
Reorganization Value, Methodology and Assumptions | Our corporate headquarters building in Tulsa, Oklahoma was completed in May 2016 and resides on approximately 30 acres. To determine its fair value, we used a market-based approach based on comparable tenant rates in our area. | |
Other Property | ||
Reorganization Value, Methodology and Assumptions | Gas gathering and processing equipment, transportation equipment and other equipment was valued using a market-based approach estimating what a market participant would pay for similar equipment in an orderly transaction. We used varying ranges of economic obsolescence rates depending on the underlying asset group. For pipelines and right-of-ways, we used a value per acre based on the location of the asset and estimated an average value of $129 per rod. We then applied an economic obsolescence rate of approximately 64% to determine the ultimate fair value. | |
Minimum | ||
Enterprise value | 270,000 | |
Maximum | ||
Enterprise value | 380,000 | |
Median | ||
Enterprise value | $ 325,000 |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details) | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
CVR Refining, LP | Oil and Natural Gas | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 14.00% | 15.00% | 14.00% |
Plains Marketing L.P. | Oil and Natural Gas | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 11.00% | ||
EOG Resources, Inc. | Drilling | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 28.00% | 20.00% | 12.00% |
QEP Resources, Inc. | Drilling | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 23.00% | 10.00% | 12.00% |
Citizen Energy III, LLC | Drilling | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 16.00% | ||
Slawson Exploration Company, Inc | Drilling | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 16.00% | 21.00% | 11.00% |
Cimarex Energy Co. | Drilling | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 12.00% | ||
ONEOK, Inc. | Mid-Stream | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 28.00% | 31.00% | 33.00% |
Range Resources Corporation | Mid-Stream | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 15.00% | 21.00% | 13.00% |
Centerpoint Energy Service, Inc. | Mid-Stream | |||
Revenue, Major Customer [Line Items] | |||
Segment's revenues | 10.00% |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Schedule of Fair Values of the Net Asset (Liabilities)) (Details) $ in Millions | Dec. 31, 2020USD ($) |
Derivative Counterparty [Line Items] | |
Total net assets | $ (5.7) |
Bank of Oklahoma | |
Derivative Counterparty [Line Items] | |
Total net assets | (5.4) |
Bank of Montreal | |
Derivative Counterparty [Line Items] | |
Total net assets | $ (0.3) |
Summary Of Significant Accoun_6
Summary Of Significant Accounting Policies (Narrative) (Details) | 3 Months Ended | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
Mar. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2020USD ($)MMcf | Aug. 31, 2020USD ($) | Dec. 31, 2020USD ($)contractPartnershipsMMcf | Dec. 31, 2019USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||||
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | We consolidate the activities of Superior, a 50/50 joint venture between Unit and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 19 – Variable Interest Entity Arrangements. | ||||||
Number of contracts, daywork expiring in one year | contract | 3 | ||||||
Number of contracts, daywork expiring in two years | contract | 2 | ||||||
Bank Overdrafts | $ 8,700,000 | $ 2,600,000 | $ 2,600,000 | $ 8,700,000 | |||
Concentration of cash | 1,700,000 | 21,400,000 | 21,400,000 | 1,700,000 | |||
Loss on abandonment of assets | 0 | $ 18,733,000 | 0 | ||||
Interest Costs Capitalized | 16,200,000 | ||||||
Goodwill impairment | $ 62,800,000 | ||||||
Goodwill, Impairment Loss, Net of Tax | 59,800,000 | ||||||
Additions to goodwill | 0 | ||||||
Directly related overhead costs capitalized | 16,500,000 | 16,500,000 | |||||
Average rates used for depreciation, depletion, and amortization per Boe | 4.21 | 7.77 | 9.66 | ||||
Ceiling test write-down | 559,400,000 | 559,400,000 | |||||
Unproved properties included in amortization | 73,900,000 | 226,500,000 | 73,900,000 | ||||
Non-cash ceiling test write-down net of tax | $ 220,800,000 | 294,500,000 | $ 127,900,000 | 346,600,000 | $ 422,400,000 | 422,400,000 | |
Eliminated yielding | 1,600,000 | ||||||
Number of oil and gas limited partnerships | Partnerships | 13 | ||||||
Repurchase of limited units outstanding amount | 600,000 | ||||||
Liability recognized to under production | $ (3,838,000) | (3,997,000) | $ (3,997,000) | $ (3,838,000) | |||
Drilling Equipment | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Minimum depreciation percentage for idle drilling rigs (if idle under 48 months) | 20.00% | ||||||
Loss on abandonment of assets | 1,100,000 | ||||||
Building | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Useful life, years | 39 years | ||||||
SCR drilling rigs | Drilling Equipment | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Impairment of Long-Lived Assets Held-for-use | 407,100,000 | ||||||
Other drilling equipment | Drilling Equipment | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Impairment of Long-Lived Assets Held-for-use | 3,000,000 | ||||||
BOSS drilling rigs | Drilling Equipment | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Carrying value of asset group | $ 242,500,000 | ||||||
Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of daywork contracts | contract | 9 | ||||||
Loss on abandonment of assets | $ 1,092,000 | ||||||
Minimum | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of days for drilling of one well | 10 days | ||||||
Contact duration | 2 months | ||||||
Insurance coverage | 0 | $ 0 | |||||
Minimum | Drilling Equipment | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Useful life, years | 15 years | ||||||
Minimum | Property, Plant and Equipment, Other Types | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Useful life, years | 3 years | ||||||
Minimum | Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of days for drilling of one well | 10 days | ||||||
Contact duration | 2 months | ||||||
Maximum | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of days for drilling of one well | 90 days | ||||||
Contact duration | 1 year | ||||||
Insurance coverage | $ 1,000,000 | $ 1,000,000 | |||||
Maximum | Property, Plant and Equipment, Other Types | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Useful life, years | 15 years | ||||||
Maximum | Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of days for drilling of one well | 90 days | ||||||
Contact duration | 3 years | ||||||
Under-Produced Properties | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Natural gas balancing (MMcf) | MMcf | 3,300,000 | 3,300,000 | |||||
Over-Produced Properties | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Natural gas balancing (MMcf) | MMcf | 3,300,000 | 3,300,000 | |||||
Natural Gas Balancing | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Accounts receivable | $ 3,400,000 | $ 3,400,000 | |||||
Long-term Contract with Customer [Member] | Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Number of daywork contracts | contract | 5 | ||||||
Long-term Contract with Customer [Member] | Minimum | Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Contact duration | 2 months | ||||||
Long-term Contract with Customer [Member] | Maximum | Drilling | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Contact duration | 1 year | ||||||
Salvage Value [Member] | |||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||
Change in Accounting Estimate, Description | During the fourth quarter 2019, we reassessed estimated salvage values associated with our oil and natural gas operations. Based on market conditions for our industry and the substantial doubt that existed for our ability to continue as a going concern, we revised these estimates downward for a total adjustment of $39.7 million ($25.6 million discounted for our full cost ceiling test) to salvage value estimates. | ||||||
Change in estimate for salvage value | $ 39,700,000 | ||||||
Change in estimate for salvage value, discounted | $ 25,600,000 |
Revenue from Contracts with C_3
Revenue from Contracts with Customers (Revenue, Remaining Performance Obligation) (Details) - Mid-Stream - Demand fee contracts [Member] $ in Thousands | Dec. 31, 2020USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining impact to revenue | $ (2,085) |
2021 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining impact to revenue | (3,501) |
2022 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining impact to revenue | 1,380 |
2023 and beyond | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining impact to revenue | $ 36 |
Minimum | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining term of contract | 2 years |
Maximum | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining term of contract | 8 years |
Revenue from Contracts with C_4
Revenue from Contracts with Customers (Contract with Customer, Asset and Liability) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | |
Adoption of ASC606 [Line Items] | ||||
Current contract assets | $ 6,084 | $ 6,084 | $ 6,664 | |
Non-current contract assets | 173 | 173 | 6,257 | |
Current contract liabilities | 2,583 | 2,583 | 2,889 | |
Change in current contract liabilities | (306) | |||
Non-current contract liabilities | 1,589 | 1,589 | 4,172 | |
Change in noncurrent contract liabilities | (2,583) | |||
Contract liability | 4,172 | 4,172 | 7,061 | |
Change in contact assets and liabilities, net | 1,316 | $ 2,459 | (2,577) | |
Mid-Stream | ||||
Adoption of ASC606 [Line Items] | ||||
Change in current contract assets | (580) | |||
Change in noncurrent contract assets | (6,084) | |||
Total contract assets | 6,257 | 6,257 | 12,921 | |
Change in contract assets | (6,664) | |||
Contract liability | 4,172 | 4,172 | 7,061 | |
Change in contract liabilities | (2,889) | |||
Contract assets (liabilities), net | $ 2,085 | 2,085 | 5,860 | |
Change in contact assets and liabilities, net | $ 3,775 | $ (2,600) |
Revenue from Contracts with C_5
Revenue from Contracts with Customers (Narrative) (Details) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | ||
Dec. 31, 2020USD ($) | Aug. 31, 2020USD ($) | Dec. 31, 2020USD ($)contract | Dec. 31, 2019USD ($) | Jan. 01, 2018USD ($) | |
Segment Reporting Information [Line Items] | |||||
Retained earnings (deficit) | $ (18,140) | $ (18,140) | $ 199,135 | ||
Change in contact assets and liabilities, net | 1,316 | $ 2,459 | (2,577) | ||
Shortfall fees recognized | $ 4,000 | $ 1,300 | 0 | ||
Minimum | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 2 months | ||||
Number of days for drilling of one well | 10 days | ||||
Maximum | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 1 year | ||||
Number of days for drilling of one well | 90 days | ||||
Oil and Natural Gas | |||||
Segment Reporting Information [Line Items] | |||||
Revenue Satisfied at Point in Time, Transfer of Control | Revenues from our sales are recognized when our customer obtains control of the sold product. For sales we make to other mid-stream and downstream oil and gas companies, control typically occurs at a point on delivery to the customer. | ||||
Oil and Natural Gas | Adjustments due to ASC606 [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Retained earnings (deficit) | $ 0 | ||||
Drilling | |||||
Segment Reporting Information [Line Items] | |||||
Revenue Satisfied over Time, Method Used | At inception, the total transaction price is estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal)), and penalties (if material and can be reasonably estimated without significant reversal). The estimation of the transaction price for unconstrained variable consideration does not differ materially from the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/recognized over the entire performance obligation. Such balances if material will be amortized over the recognition period based on the same method of measure used for revenue. | ||||
Number of daywork contracts | contract | 9 | ||||
Revenue, Practical Expedient, Initial Application and Transition, Qualitative Assessment | Most of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts with a longer duration are not material. | ||||
Drilling | Long-term Contract with Customer [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Number of daywork contracts | contract | 5 | ||||
Drilling | Minimum | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 2 months | ||||
Number of days for drilling of one well | 10 days | ||||
Drilling | Minimum | Long-term Contract with Customer [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 2 months | ||||
Drilling | Maximum | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 3 years | ||||
Number of days for drilling of one well | 90 days | ||||
Drilling | Maximum | Long-term Contract with Customer [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Contact duration | 1 year | ||||
Mid-Stream | |||||
Segment Reporting Information [Line Items] | |||||
Change in contact assets and liabilities, net | $ 3,775 | $ (2,600) | |||
Mid-Stream | Adjustments due to ASC606 [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Adjustment to opening retained earnings, before tax | (1,700) | ||||
Adjustment to opening retained earnings, after tax | $ (1,300) |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Narrative (Details) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020USD ($) | Aug. 31, 2020USD ($) | Dec. 31, 2020USD ($)rig | Dec. 31, 2019USD ($)rigmilesOfPipeline | |
Acquisitions and Divestitures [Line Items] | ||||
Net book value of drilling rigs sold | $ 5,700 | |||
Gain (loss) on sale of drilling rigs | 1,100 | |||
Assets held for sale | $ 0 | $ 0 | 5,908 | |
Oil and Natural Gas | ||||
Acquisitions and Divestitures [Line Items] | ||||
Other acquisitions | $ 400 | 3,700 | ||
Proceeds from divestiture of assets | $ 400 | $ 1,200 | $ 21,800 | |
Drilling Equipment | ||||
Acquisitions and Divestitures [Line Items] | ||||
Number of rigs sold | rig | 6 | |||
Number of drilling rigs in assets held for sale | rig | 7 | |||
Mid-Stream | ||||
Acquisitions and Divestitures [Line Items] | ||||
Other acquisitions | $ 16,100 | |||
Pipeline acquired | milesOfPipeline | 572 | |||
Business Acquisition, Effective Date of Acquisition | Dec. 1, 2019 |
Earnings Per Share (Schedule Of
Earnings Per Share (Schedule Of Earnings (Loss) Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | ||
Earnings Per Share [Abstract] | |||||||||||||
Income (loss) of basic earnings (loss) attributable to Unit Corporation per common share | $ (8,968) | $ 55,131 | $ (9,172) | $ (215,649) | $ (770,494) | $ (334,980) | [1] | $ (206,886) | $ (8,509) | $ (3,504) | $ (18,140) | $ (931,012) | $ (553,879) |
Income (loss) of effect of dilutive stock options and restricted stock | 0 | ||||||||||||
Income (loss) of diluted earnings (loss) attributable to Unit Corporation per common share | $ (553,879) | ||||||||||||
Weighted shares of basic earnings (loss) attributable to Unit Corporation per common share | 12,000 | 53,368 | 52,849 | ||||||||||
Weighted shares of effect of dilutive stock options and restricted stock | 0 | ||||||||||||
Weighted shares of diluted earnings (loss) attributable to Unit Corporation per common share | 52,849 | ||||||||||||
Per share amount of basic earnings (loss) attributable to Unit Corporation per common share | $ (0.75) | $ 1.03 | $ (0.76) | $ (4.03) | $ (14.50) | $ (6.33) | $ (3.91) | $ (0.16) | $ (0.07) | $ (1.51) | $ (17.45) | $ (10.48) | |
Per share amount of effect of dilutive stock options and restricted stock | 0 | ||||||||||||
Diluted loss attributable to Unit Corporation per common share | $ (0.75) | $ 1.03 | $ (0.76) | $ (4.03) | $ (14.50) | $ (6.33) | $ (3.91) | $ (0.16) | $ (0.07) | $ (1.51) | $ (17.45) | $ (10.48) | |
[1] | During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. 4. During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax. 5. During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets. 6. During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax. 7. During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net. |
Earnings (Loss) Per Share (Sche
Earnings (Loss) Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - Stock Options | 12 Months Ended |
Dec. 31, 2019$ / sharesshares | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |
Options | shares | 42,000 |
Average Exercise Price | $ / shares | $ 48.56 |
Earnings (Loss) Per Share (Narr
Earnings (Loss) Per Share (Narrative) (Details) - $ / shares | Dec. 31, 2020 | Sep. 01, 2020 | Dec. 31, 2019 |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Shares, Issued | 12,000,000 | ||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.20 |
Accrued Liabilities (Accrued Li
Accrued Liabilities (Accrued Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Dec. 31, 2019 |
Accrued Liabilities [Abstract] | |||
Employee costs | $ 8,878 | $ 17,832 | |
Lease operating expenses | 6,405 | 9,200 | |
Taxes | 2,324 | 3,450 | |
Litigation settlements | 2,070 | $ 45,000 | 0 |
Interest payable | 884 | 6,562 | |
Third-party credits | 0 | 3,691 | |
Other | 1,182 | 5,827 | |
Total accrued liabilities | $ 21,743 | $ 46,562 |
Long-Term Debt And Other Long_3
Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Current portion of long-term debt: | ||
Line of Credit, Current | $ 600 | $ 108,200 |
Long-term debt: | ||
Total long-term debt | 98,400 | 663,216 |
Long-term Debt | ||
Long-term debt: | ||
Total principal amount | 98,400 | 666,500 |
Less: unamortized discount | 0 | 971 |
Less: debt issuance costs, net | 0 | (2,313) |
Total long-term debt | 98,400 | 663,216 |
Long-term Debt | Senior Subordinated Notes [Member] | ||
Long-term debt: | ||
Predecessor 6.625% senior subordinated notes due 2021 | 0 | $ 650,000 |
Interest percentage of senior subordinated notes | 6.625% | |
Superior Credit Agreement [Member] | Long-term Debt | ||
Long-term debt: | ||
Long-term Line of Credit | 0 | $ 16,500 |
Revolving credit facility interest rate | 3.90% | |
Predecessor Credit Agreement [Member] | Current portion of long-term debt | ||
Current portion of long-term debt: | ||
Line of Credit, Current | $ 0 | $ 108,200 |
Long-term debt: | ||
Revolving credit facility interest rate | 4.00% | |
Successor Exit Facility | ||
Long-term debt: | ||
Revolving credit facility interest rate | 6.60% | |
Successor Exit Facility | Current portion of long-term debt | ||
Current portion of long-term debt: | ||
Line of Credit, Current | $ 600 | $ 0 |
Successor Exit Facility | Long-term Debt | ||
Long-term debt: | ||
Long-term Line of Credit | $ 98,400 | $ 0 |
Long-Term Debt And Other Long_4
Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Long-term debt and other long-term liabilites [Abstract] | |||||
ARO liability | $ 23,356 | $ 24,591 | $ 38,984 | $ 66,627 | |
Workers' compensation | 10,164 | 11,510 | |||
Separation benefit plans | [1] | 4,201 | 10,122 | ||
Contract liability | 4,172 | 7,061 | |||
Gas balancing liability | 3,997 | 3,838 | |||
Finance lease obligations | 3,216 | 7,379 | |||
Other long-term liability | 1,321 | 0 | |||
Deferred compensation plan | 0 | 6,180 | |||
Other liabilities | 50,427 | 112,717 | |||
Current portion of other long-term liabilities | 11,168 | 17,376 | |||
Other long-term liabilities | $ 39,259 | $ 95,341 | |||
[1] | As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay. |
Long-Term Debt And Other Long_5
Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) - USD ($) $ in Thousands | Sep. 03, 2020 | Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | May 26, 2020 | May 22, 2020 |
Debt Instrument [Line Items] | |||||||
Current portion of long-term debt (Note 9) | $ 600 | $ 600 | $ 108,200 | ||||
Write off of Deferred Debt Issuance Cost | 0 | $ (2,426) | $ 0 | ||||
Predecessor Credit Agreement [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fee percentage under credit facility | 0.375% | ||||||
Origination, agency and syndication fees | $ 3,300 | $ 3,300 | |||||
Write off of Deferred Debt Issuance Cost | $ (2,400) | ||||||
Debt instrument, variable interest rate, payable assessment period | 90 days | ||||||
LIBOR interest rate plus one percent plus a margin | LIBOR plus 1.00% plus a margin | ||||||
Predecessor Credit Agreement [Member] | Minimum | |||||||
Debt Instrument [Line Items] | |||||||
LIBOR plus interest rate | 1.50% | ||||||
Predecessor Credit Agreement [Member] | Maximum | |||||||
Debt Instrument [Line Items] | |||||||
LIBOR plus interest rate | 2.50% | ||||||
Predecessor Credit Agreement [Member] | Proved developed producing total value of our oil and gas properties | |||||||
Debt Instrument [Line Items] | |||||||
Percentage of collateral pledged | 80.00% | 80.00% | |||||
Oil and Gas Property, Full Cost Method, Discount Percentage | 8.00% | ||||||
Superior Credit Agreement [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Credit Facility Maximum Credit Amount | $ 250,000 | $ 250,000 | |||||
Commitment fee percentage under credit facility | 0.375% | ||||||
Origination, agency and syndication fees | 1,700 | $ 1,700 | |||||
Superior Credit Agreement, Initiation Date | May 10, 2018 | ||||||
Superior Credit Agreement, Term | 5 years | ||||||
Credit facility current credit amount | $ 200,000 | $ 200,000 | |||||
Superior Credit Agreement, Interest Rate Description | annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement) plus the applicable margin of 1.00% to 2.25%. | ||||||
Consolidated EBITDA to interest expense ratio | 2.50 to 1.00 | ||||||
Funded debt to consolidated EBITDA ratio | 4.00 to 1.00 | ||||||
Covenant Compliance | As of December 31, 2020, Superior was in compliance with these covenants. | ||||||
Successor Exit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Current ratio of credit facility | 0.50 | ||||||
Interest Coverage Ratio | 2.50 | ||||||
Successor Exit Facility | September 1, 2020 to March 31, 2021 | |||||||
Debt Instrument [Line Items] | |||||||
Net leverage ratio | 4 | ||||||
Successor Exit Facility | April 1, 2021 to June 30, 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Net leverage ratio | 3.75 | ||||||
Successor Exit Facility | July 1, 2022 to September 30, 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Net leverage ratio | 3.50 | ||||||
Successor Exit Facility | Revolving Credit Facility | Alternate Base Rate | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 4.25% | ||||||
Successor Exit Facility | Revolving Credit Facility | Eurodollar | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 5.25% | ||||||
Successor Exit Facility | Term loan | Alternate Base Rate | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 5.25% | ||||||
Successor Exit Facility | Term loan | Eurodollar | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 6.25% | ||||||
Successor Exit Facility | Letter of Credit | |||||||
Debt Instrument [Line Items] | |||||||
Letters of Credit Outstanding, Amount | $ 6,700 | ||||||
Successor Exit Facility | Secured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Maturity Date | Mar. 1, 2024 | ||||||
Successor Exit Facility | Secured Debt | Revolving Credit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Credit Facility Maximum Credit Amount | $ 140,000 | ||||||
Long-term Line of Credit | 92,000 | ||||||
Successor Exit Facility | Secured Debt | Term loan | |||||||
Debt Instrument [Line Items] | |||||||
Credit Facility Maximum Credit Amount | 40,000 | ||||||
Long-term Line of Credit | $ 40,000 | ||||||
DIP credit facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debtor-in-Possession Financing, Amount Arranged | $ 18,000 | $ 36,000 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | Sep. 01, 2020 | Dec. 31, 2020 | Aug. 31, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | ||||
ARO liability, Beginning Balance: | $ 38,984 | $ 38,984 | $ 66,627 | |
Accretion of discount | 467 | 1,545 | ||
Liability incurred | 151 | 465 | ||
Liability settled | (95) | (838) | ||
Liability sold | 0 | (487) | ||
Revision of estimates | [1] | (1,758) | (28,328) | |
Fresh start adjustments | (14,393) | |||
ARO liability, Ending Balance: | $ 24,591 | 23,356 | $ 38,984 | |
Less current portion | 2,121 | |||
Total long-term ARO liability | $ 21,235 | |||
[1] | Plugging liability estimates were revised in 2019 and 2020 for updates in the cost of services used to plug wells over the preceding year and estimated dates to be plugged. |
Income Taxes (Reconciliation Of
Income Taxes (Reconciliation Of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) computed by applying the statutory rate | $ (3,001) | $ (190,103) | $ (144,092) |
State income tax expense (benefit), net of federal benefit | (500) | (31,684) | (21,733) |
Deferred tax liability revaluation | 0 | 0 | 0 |
Restricted stock shortfall | 0 | 7,404 | 347 |
Non-controlling interest in Superior | (1,017) | 7,504 | (11) |
Goodwill impairment | 0 | 0 | 12,346 |
Valuation allowance | 4,047 | 177,284 | 19,654 |
Reorganization adjustments | 0 | 14,152 | 0 |
Statutory depletion and other | 169 | 813 | 1,163 |
Income tax benefit | $ (302) | $ (14,630) | $ (132,326) |
Income Taxes (Schedule Of Total
Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |||
Current taxes, Federal | $ 0 | $ (917) | $ (918) |
Current taxes, State | (302) | 0 | (363) |
Current taxes | (302) | (917) | (1,281) |
Deferred taxes, Federal | 0 | (16,663) | (108,440) |
Deferred taxes, State | 0 | 2,950 | (22,605) |
Deferred taxes | 0 | (13,713) | (131,045) |
Total provision | $ (302) | $ (14,630) | $ (132,326) |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Income Tax Disclosure [Abstract] | ||
Allowance for losses and nondeductible accruals | $ 22,051 | $ 31,822 |
Net operating loss carryforward | 100,236 | 246,927 |
Depreciation, depletion, amortization, and impairment | 80,947 | 0 |
Alternative minimum tax and research and development tax credit carryforward | 1,738 | 2,656 |
Deferred tax assets, total | 204,972 | 281,405 |
Depreciation, depletion, amortization, and impairment | 0 | (226,034) |
Investment in Superior | (3,987) | (49,430) |
Net deferred tax asset (liability) | 200,985 | 5,941 |
Valuation allowance | (200,985) | (19,654) |
Non-current-deferred tax liability | $ 0 | $ (13,713) |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Sep. 01, 2020 | Dec. 31, 2019 | |
Operating Loss Carryforwards [Line Items] | |||
Cancellation of debt income not recognized for tax | $ 506,300 | ||
Reduction to Operating Loss Carryforward due to CODI | 457,500 | ||
Reduction in tax basis for assets | $ 48,800 | ||
Valuation Allowance, Commentary | During the year ended December 31, 2019, in evaluating whether it was more likely than not that the company's deferred tax assets were realizable through future net income, we considered all available positive and negative evidence, including (i) our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) our ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) future revenue and operating cost projections that indicate the company will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, we determined it was more likely than not that the deferred tax asset for net operating loss carryforwards were not fully realizable. As of December 31, 2019, a total valuation allowance of $19.7 million has been recorded. | ||
Valuation allowance | $ 200,985 | $ 19,654 | |
Operating loss carryforwards | 409,100 | $ 726,400 | |
Operating loss carryforwards subject to expiration | $ 223,000 | $ 584,200 | |
Operating loss carryforwards expiration | expire from 2021 to 2037 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | ||
Defined Benefit Plan Disclosure [Line Items] | ||||
Recognized stock compensation expense | $ 6,100 | [1] | $ 12,800 | |
Deferred compensation plan | $ 0 | $ 6,180 | ||
Employee Thrift Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Contribution of shares, common stock | 310,797 | |||
Recognized stock compensation expense | 700 | 1,400 | $ 5,200 | |
Separation Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Separation benefit plans expense | $ 1,400 | $ 18,100 | $ 3,800 | |
[1] | When the company's equity-based awards were cancelled on the Effective Date, we immediately recognized the expense for the cancelled awards of $1.4 million as reorganization costs, net. |
Transactions With Related Par_2
Transactions With Related Parties (Narrative) (Details) | 12 Months Ended | |
Dec. 31, 2020USD ($)Partnerships | Dec. 31, 2019USD ($) | |
Related Party Transaction [Line Items] | ||
Number of oil and gas limited partnerships for employee investment | Partnerships | 13 | |
Repurchase of limited units outstanding amount | $ 600,000 | |
G. Bailey Peyton IV | ||
Related Party Transaction [Line Items] | ||
Payments for royalties | $ 200,000 | $ 400,000 |
Peyton Royalties, LP | G. Bailey Peyton IV | ||
Related Party Transaction [Line Items] | ||
Related party ownership percentage | 99.50% |
Stock-Based Compensation (Sched
Stock-Based Compensation (Schedule Of Restricted Stock Awards) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | ||
Share-based Payment Arrangement [Abstract] | ||||
Recognized stock compensation expense | $ 6,100 | [1] | $ 12,800 | |
Capitalized stock compensation cost for our oil and natural gas properties | 0 | 2,400 | ||
Tax benefit on stock based compensation | 1,500 | $ 3,100 | ||
Acceleration of Predecessor stock compensation expense | $ 0 | $ 1,431 | ||
[1] | When the company's equity-based awards were cancelled on the Effective Date, we immediately recognized the expense for the cancelled awards of $1.4 million as reorganization costs, net. |
Stock-Based Compensation (Activ
Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) - $ / shares | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 |
Restricted Stock - Employee | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares, beginning balance | 915,741 | 2,369,022 | 1,877,008 |
Weighted average price, beginning balance | $ 17.92 | $ 18.95 | $ 19.70 |
Number of shares, granted | 0 | 1,427,429 | |
Weighted average price, granted | $ 0 | $ 16.09 | |
Number of shares, vested | (677,076) | (803,942) | |
Weighted average price, vested | $ 19.95 | $ 15.56 | |
Number of shares, forfeited | (776,205) | (131,473) | |
Weighted average price, forfeited | $ 19.28 | $ 19.36 | |
Number of shares, cancelled | (915,741) | ||
Weighted average price, cancellation | $ 17.92 | ||
Number of shares, ending balance | 0 | 915,741 | 2,369,022 |
Weighted average price, ending balance | $ 0 | $ 17.92 | $ 18.95 |
Restricted Stock - Non-employee Directors | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares, beginning balance | 70,213 | 118,688 | 107,045 |
Weighted average price, beginning balance | $ 14.10 | $ 14.83 | $ 17.07 |
Number of shares, granted | 0 | 72,784 | |
Weighted average price, granted | $ 0 | $ 12.09 | |
Number of shares, vested | (48,475) | (61,141) | |
Weighted average price, vested | $ 15.88 | $ 15.49 | |
Number of shares, forfeited | 0 | 0 | |
Weighted average price, forfeited | $ 0 | $ 0 | |
Number of shares, cancelled | (70,213) | ||
Weighted average price, cancellation | $ 14.10 | ||
Number of shares, ending balance | 0 | 70,213 | 118,688 |
Weighted average price, ending balance | $ 0 | $ 14.10 | $ 14.83 |
Time Vested | Restricted Stock - Employee | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares, beginning balance | 578,176 | 1,527,648 | 1,268,883 |
Number of shares, granted | 0 | 927,173 | |
Number of shares, vested | (677,076) | (570,107) | |
Number of shares, forfeited | (272,396) | (98,301) | |
Number of shares, cancelled | (578,176) | ||
Number of shares, ending balance | 0 | 578,176 | 1,527,648 |
Performance Shares | Restricted Stock - Employee | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares, beginning balance | 337,565 | 841,374 | 608,125 |
Number of shares, granted | 0 | 500,256 | |
Number of shares, vested | 0 | (233,835) | |
Number of shares, forfeited | (503,809) | (33,172) | |
Number of shares, cancelled | (337,565) | ||
Number of shares, ending balance | 0 | 337,565 | 841,374 |
Stock-Based Compensation (Act_2
Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) - Directors Plan - $ / shares | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares, beginning balance | 28,000 | 42,000 | 66,500 |
Weighted average price, beginning balance | $ 52.24 | $ 48.56 | $ 44.42 |
Number of shares, granted | 0 | 0 | |
Weighted average price, granted | $ 0 | $ 0 | |
Number of shares, exercised | 0 | 0 | |
Weighted average price, exercised | $ 0 | $ 0 | |
Number of shares, forfeited | (14,000) | (24,500) | |
Weighted average price, forfeited | $ 41.21 | $ 37.31 | |
Number of shares, cancelled | 28,000 | ||
Weighted average price, cancellation | $ 52.24 | ||
Number of shares, ending balance | 0 | 28,000 | 42,000 |
Weighted average price, ending balance | $ 0 | $ 52.24 | $ 48.56 |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Thousands | 8 Months Ended | 12 Months Ended | |||
Aug. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | Sep. 03, 2020 | May 06, 2015 | |
Restricted Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum number of shares of common stock allowed for the issuance | 903,226 | 7,230,000 | |||
Vesting Period | 3 years | ||||
Grant date fair value | $ 22,600 | ||||
Directors Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Director option awards | 3,500 | ||||
Incentive Stock Grants | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum number of shares of common stock allowed for the issuance | 2,000,000 | ||||
Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Reversal of previously recorded expense for unvested awards | $ (2,200) |
Derivatives (Schedule of Non-de
Derivatives (Schedule of Non-designated Hedges Outstanding) (Details) | 12 Months Ended |
Dec. 31, 2020$ / UnitMMBTUMMBoebbl | |
Natural gas | Basis Swap | NGPL Texok | Jan'21 - Dec'21 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBTU | 30,000 |
Swap price | (0.215) |
Natural gas | Swap | If Nymex | Jan'21 - Oct'21 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBTU | 50,000 |
Swap price | 2.818 |
Natural gas | Swap | If Nymex | Nov'21 - Dec'21 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBTU | 45,000 |
Swap price | 2.900 |
Natural gas | Swap | If Nymex | Jan'22 - Dec'22 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBTU | 5,000 |
Swap price | 2.605 |
Natural gas | Swap | If Nymex | Jan'23 - Dec'23 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBoe | 22,000 |
Swap price | 2.456 |
Natural gas | Collar | If Nymex | Jan'22 - Dec'22 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Mmbtu) | MMBTU | 35,000 |
Derivative, Floor Price | 2.50 |
Derivative, Cap Price | 2.68 |
Crude Oil | Swap | Wti Nymex [Member] | Jan'21 - Dec'21 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Bbl) | bbl | 3,000 |
Swap price | 44.65 |
Crude Oil | Swap | Wti Nymex [Member] | Jan'22 - Dec'22 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Bbl) | bbl | 2,300 |
Swap price | 42.25 |
Crude Oil | Swap | Wti Nymex [Member] | Jan'23 - Dec'23 | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Hedged Volume (Bbl) | bbl | 1,300 |
Swap price | 43.60 |
Derivatives (Fair Value Of Deri
Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Current derivative assets | $ 0 | $ 633 |
Non-current derivative assets | 0 | 0 |
Total derivatives assets | 0 | 633 |
Current derivative liabilities | 1,047 | 0 |
Non-current derivative liabilities | 4,659 | 27 |
Total derivative liabilities | $ 5,706 | $ 27 |
Derivatives (Effect Of Derivati
Derivatives (Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivatives | $ (985) | $ (10,704) | $ 4,225 |
Derivative Instruments Not Designated Amount Paid (Received) During Period | (1,133) | (4,244) | 16,196 |
Commodity Contract | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivatives | $ (985) | $ (10,704) | $ 4,225 |
Fair Value Measurements (Recurr
Fair Value Measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets (liabilities) | $ (5,700) | |
Commodity Contract | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Assets | 0 | $ 633 |
Liabilities | (5,706) | (27) |
Financial assets (liabilities) | (5,706) | 606 |
Commodity Contract | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Assets | 3,436 | 177 |
Liabilities | (9,142) | (775) |
Financial assets (liabilities) | (5,706) | (598) |
Commodity Contract | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Assets | 0 | 1,204 |
Liabilities | 0 | 0 |
Financial assets (liabilities) | 0 | 1,204 |
Commodity Contract | Effect of Netting | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Assets | (3,436) | (748) |
Liabilities | 3,436 | 748 |
Financial assets (liabilities) | $ 0 | $ 0 |
Fair Value Measurements (Reconc
Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |||
Beginning of period | $ 0 | $ 1,204 | $ 10,630 |
Included in earnings | 0 | 978 | (1,494) |
Settlements | 0 | (2,182) | (7,932) |
End of period | 0 | 0 | 1,204 |
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period | $ 0 | $ (1,204) | $ (9,426) |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | $ 0 | |
Transfers between Level 2 and Level 3 assets (liabilities) | 0 | |
Warrant liability | 885 | $ 0 |
Level 2 | ||
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items] | ||
6.625% senior subordinated notes due 2021 | 646,700 | |
Estimated fair value of long-term debt | $ 357,500 | |
Level 3 | ||
Fair Value, Option, Qualitative Disclosures Related to Election [Line Items] | ||
Warrant liability | $ 900 |
Leases (Operating leases) (Deta
Leases (Operating leases) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Ending December 31, | ||
2021 | $ 4,232 | |
2022 | 1,305 | |
2023 | 96 | |
2024 | 12 | |
2025 | 12 | |
2026 and beyond | 63 | |
Total future payments | 5,720 | |
Less: Interest | 200 | |
Present value of future minimum operating lease payments | 5,520 | |
Less: Current portion | (4,075) | $ (3,430) |
Long-term operating lease payments | $ 1,445 | $ 2,071 |
Leases (Financing leases) (Deta
Leases (Financing leases) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Ending December 31, | ||
2021 | $ 3,774 | |
Total future payments | 3,774 | |
Less payment related to: | ||
Maintenance | 525 | |
Interest | 33 | |
Finance lease obligations | 3,216 | $ 7,379 |
Current portion of finance leases | 3,216 | 4,164 |
Total long-term finance lease payments | $ 0 | $ 3,215 |
Leases (Schedule of lease asset
Leases (Schedule of lease assets and liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Leases [Abstract] | ||
Right of use asset | $ 5,592 | $ 5,673 |
Finance Lease, Right-of-Use Asset | 7,281 | 17,396 |
Right-of-use asset | 12,873 | 23,069 |
Operating Lease, Liability, Current | 4,075 | 3,430 |
Finance Lease, Liability, Current | 3,216 | 4,164 |
Operating Lease, Liability, Noncurrent | 1,445 | 2,071 |
Finance Lease, Liability, Noncurrent | 0 | 3,215 |
Lease liability | $ 8,736 | $ 12,880 |
Leases (Schedule of lease costs
Leases (Schedule of lease costs) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | |||
Finance Lease, Right-of-Use Asset, Amortization | $ 1,406 | $ 2,757 | $ 4,001 |
Finance Lease, Interest Expense | 54 | 165 | 382 |
Operating Lease, Cost | 1,331 | 3,604 | 4,034 |
Short-term lease cost | 3,664 | 8,190 | 38,868 |
Variable Lease, Cost | 64 | 223 | 351 |
Lease, Cost | 6,519 | 14,939 | 47,636 |
Capitalized costs included in short-term lease costs | $ 200 | $ 1,500 | $ 24,700 |
Leases (Supplemental cash flow
Leases (Supplemental cash flow information related to leases) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Leases [Abstract] | |||
Operating cash flows for operating leases | $ 1,489 | $ 3,849 | $ 4,034 |
Financing cash flows for finance leases | 1,407 | 2,757 | 4,001 |
Lease liabilities recognized in exchange for new operating lease right of use assets | $ 0 | $ 0 | $ 5 |
Leases (Schedule of weighted av
Leases (Schedule of weighted average discount rate for leases) (Details) | Dec. 31, 2020 | |
Leases [Abstract] | ||
Operating Lease, Weighted Average Remaining Lease Term | 1 year 7 months 6 days | |
Operating Lease, Weighted Average Discount Rate, Percent | 4.41% | [1] |
Finance Lease, Weighted Average Remaining Lease Term | 8 months 12 days | |
Finance Lease, Weighted Average Discount Rate, Percent | 4.00% | [1] |
[1] | Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease. |
Leases (Narrative) (Details)
Leases (Narrative) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Jan. 01, 2019USD ($) | |
Adoption of ASC842 [Line Items] | |||
Right of use asset | $ 5,592 | $ 5,673 | |
Total operating lease liability | $ 5,520 | ||
Number of compressors under capital lease agreement | 20 | ||
Finance lease term | 7 years | ||
Current portion of finance leases | $ 3,216 | $ 4,164 | |
Discount rate finance leases | 4.00% | ||
Maintenance | $ 525 | ||
Finance lease fair market value percentage for purchase | 10.00% | ||
Accounting Standards Update 2016-02 [Member] | |||
Adoption of ASC842 [Line Items] | |||
Right of use asset | $ 3,700 | ||
Total operating lease liability | $ 3,500 |
Commitments And Contingencies (
Commitments And Contingencies (Details) - USD ($) $ in Thousands | Jan. 31, 2019 | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 21, 2020 | Dec. 31, 2019 |
Other Commitments [Line Items] | |||||
Litigation Settlement, Amount Awarded to Other Party | $ 2,400 | ||||
Litigation settlements | $ 2,070 | $ 45,000 | $ 0 | ||
Cockerell Oil Properties, Ltd., v. Unit Petroleum Company | |||||
Other Commitments [Line Items] | |||||
Litigation settlements | $ 15,750 | ||||
Chieftan Royalty Company v. Unit Petroleum Company | |||||
Other Commitments [Line Items] | |||||
Litigation settlements | $ 29,250 | ||||
Mid-Stream | |||||
Other Commitments [Line Items] | |||||
Other Commitment, Due in Next Twelve Months | 1,000 | ||||
Other Commitment, Due in Second and Third Year | $ 400 | ||||
Oil and Natural Gas | Capital Addition Purchase Commitments [Member] | |||||
Other Commitments [Line Items] | |||||
Long-term Purchase Commitment, Description | as part of the Superior transaction (see Note 19 – Variable Interest Entity Arrangements), we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in our consolidated mid-stream subsidiary. At December 31, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. | ||||
Long-term purchase commitment, purchases made | $ 24,800 |
Variable Interest Entity Arra_3
Variable Interest Entity Arrangements (Schedule of Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Current assets: | ||||||
Cash and cash equivalents | $ 12,145 | $ 571 | $ 6,452 | |||
Accounts receivable | 57,846 | 82,656 | ||||
Prepaid expenses and other | 11,212 | 13,078 | ||||
Total current assets | 82,922 | 105,051 | ||||
Property and Equipment: | ||||||
Gas gathering and processing equipment | 251,404 | $ 250,098 | $ 833,788 | 824,699 | ||
Transportation equipment | 3,130 | $ 3,314 | $ 15,577 | 29,723 | ||
Property, plant and equipment, gross, total | 600,989 | 8,931,355 | ||||
Less accumulated depreciation, depletion, amortization, and impairment | 54,189 | 6,978,669 | ||||
Net property and equipment | 546,800 | 1,952,686 | ||||
Right of use asset | 5,592 | 5,673 | ||||
Other assets | 14,389 | 26,642 | ||||
Total assets | [1] | 649,703 | 2,090,052 | |||
Current liabilities: | ||||||
Accounts payable | 40,829 | 84,481 | ||||
Accrued liabilities | 21,743 | 46,562 | ||||
Operating Lease, Liability, Current | 4,075 | 3,430 | ||||
Current portion of other long-term liabilities | 11,168 | 17,376 | ||||
Total current liabilities | 80,347 | 260,049 | ||||
Long-term debt less debt issuance costs | 98,400 | 663,216 | ||||
Long-term operating lease payments | 1,445 | 2,071 | ||||
Other long-term liabilities | 39,259 | 95,341 | ||||
VIE | ||||||
Current assets: | ||||||
Cash and cash equivalents | 11,642 | 0 | ||||
Accounts receivable | 27,427 | 21,073 | ||||
Prepaid expenses and other | 6,746 | 7,686 | ||||
Total current assets | 45,815 | 28,759 | ||||
Property and Equipment: | ||||||
Gas gathering and processing equipment | 251,403 | 824,699 | ||||
Transportation equipment | 1,748 | 3,390 | ||||
Property, plant and equipment, gross, total | 253,151 | 828,089 | ||||
Less accumulated depreciation, depletion, amortization, and impairment | 10,466 | 407,144 | ||||
Net property and equipment | 242,685 | 420,945 | ||||
Right of use asset | 2,823 | 3,948 | ||||
Other assets | 2,309 | 9,442 | ||||
Total assets | 293,632 | 463,094 | ||||
Current liabilities: | ||||||
Accounts payable | 17,045 | 18,511 | ||||
Accrued liabilities | 3,777 | 4,198 | ||||
Operating Lease, Liability, Current | 1,762 | 2,407 | ||||
Current portion of other long-term liabilities | 5,799 | 7,060 | ||||
Total current liabilities | 28,383 | 32,176 | ||||
Long-term debt less debt issuance costs | 0 | 16,500 | ||||
Long-term operating lease payments | 1,013 | 1,404 | ||||
Other long-term liabilities | 1,589 | 8,126 | ||||
Total liabilities | $ 30,985 | $ 58,206 | ||||
[1] | Unit Corporation's consolidated total assets as of December 31, 2020 include current and long-term assets of its variable interest entity (VIE) (Superior) of $45.8 million and $247.8 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 19 – Variable Interest Entity Arrangements. |
Variable Interest Entity Arra_4
Variable Interest Entity Arrangements (Narrative) (Details) - Superior Pipeline Company, L.L.C. [Member] | 12 Months Ended |
Dec. 31, 2020USD ($) | |
Variable Interest Entity [Line Items] | |
Date Involvement Began | Apr. 3, 2018 |
Lack of Recourse | Superior's creditors have no recourse to our general credit. |
Methodology for Determining Whether Entity is Primary Beneficiary | The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA gives us the power to direct the activities that most significantly affect Superior's operating performance. The MSA is a separate variable interest. Under the MSA, Unit has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. |
SPC Midstream Operating, L.L.C. [Member] | |
Variable Interest Entity [Line Items] | |
Monthly service fee | $ 260,560 |
SP Investor Holdings, LLC [Member] | |
Variable Interest Entity [Line Items] | |
Ownership percentage | 50.00% |
Industry Segment Information (R
Industry Segment Information (Revenue From Different Segments) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | ||||
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |||||
Revenues: | |||||||
Revenues | $ 133,528 | [1] | $ 276,957 | [2] | $ 674,634 | [3] | |
Operating costs: | |||||||
Operating costs | 81,277 | 237,546 | 384,728 | ||||
Depreciation, depletion, and amortization | 27,962 | 115,496 | 275,573 | ||||
Impairments (Note 4) | 26,063 | [4] | 867,814 | [5] | 625,716 | [6] | |
Total expenses | 135,302 | 1,220,856 | 1,286,017 | ||||
Loss on abandonment of assets (Note 4) | 0 | (18,733) | 0 | ||||
General and administrative | 6,702 | 42,766 | 38,246 | ||||
Gain (Loss) on Disposition of Assets | (619) | (89) | 3,502 | ||||
Income (loss) from operations | (7,857) | (1,005,309) | (653,131) | ||||
Gain (loss) on derivatives | (985) | (10,704) | 4,225 | ||||
Write off of debt issuance costs | 0 | 2,426 | 0 | ||||
Total reorganization items, net | 2,273 | (133,975) | 0 | ||||
Interest expense, net | (3,275) | (22,824) | (37,012) | ||||
Other | 100 | 2,034 | (236) | ||||
Income (loss) before income taxes | (14,290) | (905,254) | (686,154) | ||||
Identifiable assets: | |||||||
Oil and natural gas | 232,747 | [7] | 847,398 | [8] | |||
Contract drilling | 81,608 | 708,468 | |||||
Gas gathering and processing | 293,297 | 459,444 | |||||
Total identifiable assets | 607,652 | [9] | 2,015,310 | [10] | |||
Corporate land and building | 32,382 | 54,155 | |||||
Other corporate assets | 9,669 | [11] | 20,587 | [12] | |||
Total assets | [13] | 649,703 | 2,090,052 | ||||
Capital expenditures: | |||||||
Total capital expenditures | 5,960 | 17,213 | 374,369 | ||||
Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 57,578 | [1] | 103,439 | [2] | 325,797 | [3] | |
Operating costs: | |||||||
Operating costs | 25,256 | 117,691 | 135,124 | ||||
Contract drilling | |||||||
Revenues: | |||||||
Revenues | 19,413 | [1] | 73,519 | [2] | 168,383 | [3] | |
Operating costs: | |||||||
Operating costs | 13,852 | 51,810 | 115,998 | ||||
Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | 56,537 | [1] | 99,999 | [2] | 180,454 | [3] | |
Operating costs: | |||||||
Operating costs | 42,169 | 68,045 | 133,606 | ||||
Intersubsegment Eliminations | |||||||
Revenues: | |||||||
Revenues | (11,834) | [1] | (14,536) | [2] | (63,294) | [3] | |
Operating costs: | |||||||
Operating costs | (11,833) | (14,536) | (61,675) | ||||
Depreciation, depletion, and amortization | 0 | 0 | 0 | ||||
Impairments (Note 4) | 0 | [4] | 0 | [5] | 0 | [6] | |
Total expenses | (11,833) | (14,536) | (61,675) | ||||
Loss on abandonment of assets (Note 4) | 0 | ||||||
General and administrative | 0 | 0 | 0 | ||||
Gain (Loss) on Disposition of Assets | 0 | 0 | 0 | ||||
Income (loss) from operations | (1) | 0 | (1,619) | ||||
Gain (loss) on derivatives | 0 | 0 | 0 | ||||
Write off of debt issuance costs | 0 | ||||||
Total reorganization items, net | 0 | 0 | |||||
Interest expense, net | 0 | 0 | 0 | ||||
Other | 0 | 0 | 0 | ||||
Income (loss) before income taxes | (1) | 0 | (1,619) | ||||
Identifiable assets: | |||||||
Oil and natural gas | (3,326) | [7] | (4,264) | [8] | |||
Contract drilling | (4) | (42) | |||||
Gas gathering and processing | (335) | (4,255) | |||||
Total identifiable assets | (3,665) | [9] | (8,561) | [10] | |||
Corporate land and building | 0 | 0 | |||||
Other corporate assets | (4,002) | [11] | (2,505) | [12] | |||
Total assets | (7,667) | (11,066) | |||||
Capital expenditures: | |||||||
Total capital expenditures | 0 | 0 | 0 | ||||
Intersubsegment Eliminations | Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | (2) | [1] | (4) | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | (855) | (1,973) | (4,902) | ||||
Intersubsegment Eliminations | Contract drilling | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | (15,809) | [3] | |
Operating costs: | |||||||
Operating costs | 0 | (1) | (14,190) | ||||
Intersubsegment Eliminations | Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | (11,832) | [1] | (14,532) | [2] | (47,485) | [3] | |
Operating costs: | |||||||
Operating costs | (10,978) | (12,562) | (42,583) | ||||
Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 57,580 | [1] | 103,443 | [2] | 325,797 | [3] | |
Operating costs: | |||||||
Operating costs | 26,111 | 119,664 | 140,026 | ||||
Depreciation, depletion, and amortization | 14,869 | 68,762 | 168,651 | ||||
Impairments (Note 4) | 26,063 | [4] | 393,726 | [5] | 559,867 | [6] | |
Total expenses | 67,043 | 582,152 | 868,544 | ||||
Loss on abandonment of assets (Note 4) | (17,641) | ||||||
General and administrative | 0 | 0 | 0 | ||||
Gain (Loss) on Disposition of Assets | (24) | (160) | (199) | ||||
Income (loss) from operations | (9,439) | (496,190) | (542,548) | ||||
Gain (loss) on derivatives | 0 | 0 | 0 | ||||
Write off of debt issuance costs | 0 | ||||||
Total reorganization items, net | 0 | (15,504) | |||||
Interest expense, net | 0 | 0 | 0 | ||||
Other | 56 | 458 | (481) | ||||
Income (loss) before income taxes | (9,383) | (480,228) | (543,029) | ||||
Identifiable assets: | |||||||
Oil and natural gas | 236,073 | [7] | 851,662 | [8] | |||
Contract drilling | 0 | 0 | |||||
Gas gathering and processing | 0 | 0 | |||||
Total identifiable assets | 236,073 | [9] | 851,662 | [10] | |||
Corporate land and building | 0 | 0 | |||||
Other corporate assets | 0 | [11] | 0 | [12] | |||
Total assets | 236,073 | 851,662 | |||||
Capital expenditures: | |||||||
Total capital expenditures | 4,018 | 5,350 | 268,622 | ||||
Oil and Natural Gas | Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 57,580 | [1] | 103,443 | [2] | 325,797 | [3] | |
Operating costs: | |||||||
Operating costs | 26,111 | 119,664 | 140,026 | ||||
Oil and Natural Gas | Contract drilling | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Oil and Natural Gas | Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Drilling | |||||||
Revenues: | |||||||
Revenues | 19,413 | [1] | 73,519 | [2] | 184,192 | [3] | |
Operating costs: | |||||||
Operating costs | 13,852 | 51,811 | 130,188 | ||||
Depreciation, depletion, and amortization | 2,102 | 15,544 | 51,552 | ||||
Impairments (Note 4) | 0 | [4] | 410,126 | [5] | 62,809 | [6] | |
Total expenses | 15,954 | 477,481 | 244,549 | ||||
Loss on abandonment of assets (Note 4) | (1,092) | ||||||
General and administrative | 0 | 0 | 0 | ||||
Gain (Loss) on Disposition of Assets | (521) | (1,390) | 3,872 | ||||
Income (loss) from operations | 3,980 | (403,664) | (64,229) | ||||
Gain (loss) on derivatives | 0 | 0 | 0 | ||||
Write off of debt issuance costs | 0 | ||||||
Total reorganization items, net | 0 | 183,664 | |||||
Interest expense, net | 0 | 0 | 0 | ||||
Other | 4 | 1,449 | (605) | ||||
Income (loss) before income taxes | 3,984 | (585,879) | (64,834) | ||||
Identifiable assets: | |||||||
Oil and natural gas | 0 | [7] | 0 | [8] | |||
Contract drilling | 81,612 | 708,510 | |||||
Gas gathering and processing | 0 | 0 | |||||
Total identifiable assets | 81,612 | [9] | 708,510 | [10] | |||
Corporate land and building | 0 | 0 | |||||
Other corporate assets | 0 | [11] | 0 | [12] | |||
Total assets | 81,612 | 708,510 | |||||
Capital expenditures: | |||||||
Total capital expenditures | 616 | 2,438 | 40,636 | ||||
Drilling | Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Drilling | Contract drilling | |||||||
Revenues: | |||||||
Revenues | 19,413 | [1] | 73,519 | [2] | 184,192 | [3] | |
Operating costs: | |||||||
Operating costs | 13,852 | 51,811 | 130,188 | ||||
Drilling | Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Mid-Stream | |||||||
Revenues: | |||||||
Revenues | 68,369 | [1] | 114,531 | [2] | 227,939 | [3] | |
Operating costs: | |||||||
Operating costs | 53,147 | 80,607 | 176,189 | ||||
Depreciation, depletion, and amortization | 10,659 | 29,371 | 47,663 | ||||
Impairments (Note 4) | 0 | [4] | 63,962 | [5] | 3,040 | [6] | |
Total expenses | 63,806 | 173,940 | 226,892 | ||||
Loss on abandonment of assets (Note 4) | 0 | ||||||
General and administrative | 0 | 0 | 0 | ||||
Gain (Loss) on Disposition of Assets | (55) | (18) | (160) | ||||
Income (loss) from operations | 4,618 | (59,391) | 1,207 | ||||
Gain (loss) on derivatives | 0 | 0 | 0 | ||||
Write off of debt issuance costs | 0 | ||||||
Total reorganization items, net | 0 | 71,016 | |||||
Interest expense, net | (501) | (1,888) | (1,546) | ||||
Other | 34 | 50 | 827 | ||||
Income (loss) before income taxes | 4,151 | (132,245) | 488 | ||||
Identifiable assets: | |||||||
Oil and natural gas | 0 | [7] | 0 | [8] | |||
Contract drilling | 0 | 0 | |||||
Gas gathering and processing | 293,632 | 463,699 | |||||
Total identifiable assets | 293,632 | [9] | 463,699 | [10] | |||
Corporate land and building | 0 | 0 | |||||
Other corporate assets | 0 | [11] | 0 | [12] | |||
Total assets | 293,632 | 463,699 | |||||
Capital expenditures: | |||||||
Total capital expenditures | 1,323 | 9,342 | 64,438 | ||||
Mid-Stream | Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Mid-Stream | Contract drilling | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Mid-Stream | Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | 68,369 | [1] | 114,531 | [2] | 227,939 | [3] | |
Operating costs: | |||||||
Operating costs | 53,147 | 80,607 | 176,189 | ||||
Corporate and Other | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Depreciation, depletion, and amortization | 332 | 1,819 | 7,707 | ||||
Impairments (Note 4) | 0 | [4] | 0 | [5] | 0 | [6] | |
Total expenses | 332 | 1,819 | 7,707 | ||||
Loss on abandonment of assets (Note 4) | 0 | ||||||
General and administrative | 6,702 | 42,766 | 38,246 | ||||
Gain (Loss) on Disposition of Assets | (19) | 1,479 | (11) | ||||
Income (loss) from operations | (7,015) | (46,064) | (45,942) | ||||
Gain (loss) on derivatives | (985) | (10,704) | 4,225 | ||||
Write off of debt issuance costs | 2,426 | ||||||
Total reorganization items, net | 2,273 | (373,151) | |||||
Interest expense, net | (2,774) | (20,936) | (35,466) | ||||
Other | 6 | 77 | 23 | ||||
Income (loss) before income taxes | (13,041) | 293,098 | (77,160) | ||||
Identifiable assets: | |||||||
Oil and natural gas | 0 | [7] | 0 | [8] | |||
Contract drilling | 0 | 0 | |||||
Gas gathering and processing | 0 | 0 | |||||
Total identifiable assets | 0 | [9] | 0 | [10] | |||
Corporate land and building | 32,382 | 54,155 | |||||
Other corporate assets | 13,671 | [11] | 23,092 | [12] | |||
Total assets | 46,053 | 77,247 | |||||
Capital expenditures: | |||||||
Total capital expenditures | 3 | 83 | 673 | ||||
Corporate and Other | Oil and Natural Gas | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Corporate and Other | Contract drilling | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | 0 | 0 | 0 | ||||
Corporate and Other | Gas gathering and processing | |||||||
Revenues: | |||||||
Revenues | 0 | [1] | 0 | [2] | 0 | [3] | |
Operating costs: | |||||||
Operating costs | $ 0 | $ 0 | $ 0 | ||||
[1] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | ||||||
[2] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | ||||||
[3] | The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time. | ||||||
[4] | During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax | ||||||
[5] | During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. | ||||||
[6] | We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). | ||||||
[7] | Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. | ||||||
[8] | Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets. | ||||||
[9] | Identifiable assets are those used in Unit’s operations in each industry segment. | ||||||
[10] | Identifiable assets are those used in Unit’s operations in each industry segment. | ||||||
[11] | Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. | ||||||
[12] | Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. | ||||||
[13] | Unit Corporation's consolidated total assets as of December 31, 2020 include current and long-term assets of its variable interest entity (VIE) (Superior) of $45.8 million and $247.8 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 19 – Variable Interest Entity Arrangements. |
Selected Quarterly Financial _3
Selected Quarterly Financial Information (Details) - USD ($) | 1 Months Ended | 2 Months Ended | 3 Months Ended | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||||||||||
Sep. 30, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2019 | |||||
Revenues | $ 32,846,000 | $ 65,574,000 | $ 100,682,000 | $ 89,007,000 | $ 122,376,000 | $ 164,358,000 | $ 155,439,000 | $ 165,146,000 | $ 189,691,000 | $ 276,957,000 | $ 674,634,000 | ||||||
Gross income (loss) | (7,373,000) | (7,637,000) | 5,599,000 | (171,374,000) | (764,888,000) | (393,983,000) | [1] | (242,308,000) | [1] | 813,000 | [1] | 24,095,000 | [1] | ||||
Net income (loss) attributable to Unit Corporation | $ (8,968,000) | $ 55,131,000 | $ (9,172,000) | $ (215,649,000) | $ (770,494,000) | $ (334,980,000) | [2] | $ (206,886,000) | $ (8,509,000) | $ (3,504,000) | $ (18,140,000) | $ (931,012,000) | $ (553,879,000) | ||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Basic | $ (0.75) | $ 1.03 | $ (0.76) | $ (4.03) | $ (14.50) | $ (6.33) | $ (3.91) | $ (0.16) | $ (0.07) | $ (1.51) | $ (17.45) | $ (10.48) | |||||
Diluted | $ (0.75) | $ 1.03 | $ (0.76) | $ (4.03) | $ (14.50) | $ (6.33) | $ (3.91) | $ (0.16) | $ (0.07) | $ (1.51) | $ (17.45) | $ (10.48) | |||||
Ceiling test write-down | $ 559,400,000 | $ 559,400,000 | |||||||||||||||
Non-cash ceiling test write-down net of tax | $ 220,800,000 | $ 294,500,000 | $ 127,900,000 | $ 346,600,000 | $ 422,400,000 | 422,400,000 | |||||||||||
Goodwill impairment | 62,800,000 | ||||||||||||||||
Goodwill, Impairment Loss, Net of Tax | 59,800,000 | ||||||||||||||||
Loss on abandonment of assets (Note 4) | $ 0 | (18,733,000) | $ 0 | ||||||||||||||
Oil and Natural Gas | |||||||||||||||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Ceiling test write-down | $ 13,200,000 | $ 16,600,000 | $ 12,900,000 | $ 109,300,000 | 267,800,000 | $ 390,100,000 | $ 169,300,000 | $ 26,100,000 | 393,700,000 | ||||||||
Loss on abandonment of assets (Note 4) | (17,600,000) | ||||||||||||||||
Drilling Equipment | |||||||||||||||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Loss on abandonment of assets (Note 4) | (1,100,000) | ||||||||||||||||
Drilling Equipment | Other drilling equipment | |||||||||||||||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Impairment of Long-Lived Assets Held-for-use | 3,000,000 | ||||||||||||||||
Drilling Equipment | SCR drilling rigs | |||||||||||||||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Impairment of Long-Lived Assets Held-for-use | $ 407,100,000 | ||||||||||||||||
Mid-Stream | |||||||||||||||||
Net income (loss) attributable to Unit Corporation per common share: | |||||||||||||||||
Impairment of Long-Lived Assets Held-for-use | $ 64,000,000 | ||||||||||||||||
[1] | Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, loss on abandonment of assets, gain (loss) on derivatives, reorganization items, net, income taxes, and other income (loss). | ||||||||||||||||
[2] | During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. 4. During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax. 5. During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets. 6. During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax. 7. During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net. |
Supplemental Condensed Consol_3
Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Sep. 01, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Current assets: | ||||||
Cash and cash equivalents | $ 12,145 | $ 571 | $ 6,452 | |||
Accounts receivable | 57,846 | 82,656 | ||||
Materials and supplies | 0 | 449 | ||||
Current derivative assets | 0 | 633 | ||||
Income taxes receivable | 1,150 | 1,756 | ||||
Assets held for sale | 0 | 5,908 | ||||
Prepaid expenses and other | 11,212 | 13,078 | ||||
Total current assets | 82,922 | 105,051 | ||||
Oil and Gas Property [Abstract] | ||||||
Proved properties | 238,581 | $ 238,284 | $ 6,539,816 | 6,341,582 | ||
Unproved properties not being amortized | 1,591 | 0 | 30,205 | 252,874 | ||
Drilling equipment | 63,687 | 63,458 | 1,285,024 | 1,295,713 | ||
Gas gathering and processing equipment | 251,404 | 250,098 | 833,788 | 824,699 | ||
Saltwater disposal systems | 0 | 0 | 43,541 | 69,692 | ||
Land and building | 32,635 | 32,635 | 59,080 | 59,080 | ||
Transportation equipment | 3,130 | 3,314 | 15,577 | 29,723 | ||
Other | 9,961 | 9,958 | 57,427 | 57,992 | ||
Property, plant and equipment, gross, total | 600,989 | 8,931,355 | ||||
Less accumulated depreciation, depletion, amortization, and impairment | 54,189 | 6,978,669 | ||||
Net property and equipment | 546,800 | 1,952,686 | ||||
Intercompany receivable | 0 | |||||
Investments | 0 | |||||
Right of use asset | 5,592 | 5,673 | ||||
Other assets | 26,642 | |||||
Total assets | [1] | 649,703 | 2,090,052 | |||
Current liabilities: | ||||||
Accounts payable | 40,829 | 84,481 | ||||
Accrued liabilities | 21,743 | 46,562 | ||||
Operating Lease, Liability, Current | 4,075 | 3,430 | ||||
Current portion of long-term debt (Note 9) | 600 | 108,200 | ||||
Current portion of other long-term liabilities | 11,168 | 17,376 | ||||
Total current liabilities | 80,347 | 260,049 | ||||
Intercompany debt | 0 | |||||
Long-term debt less debt issuance costs | 98,400 | 663,216 | ||||
Non-current derivative liabilities | 4,659 | 27 | ||||
Long-term operating lease payments | 1,445 | 2,071 | ||||
Other long-term liabilities | 39,259 | 95,341 | ||||
Deferred income taxes | 0 | 13,713 | ||||
Total shareholders' equity | 425,593 | $ 439,523 | $ 171,180 | 1,055,635 | 1,593,444 | |
Total liabilities and shareholders' equity | [1] | $ 649,703 | 2,090,052 | |||
Consolidating Adjustments | ||||||
Current assets: | ||||||
Cash and cash equivalents | 0 | 0 | ||||
Accounts receivable | (9,447) | |||||
Materials and supplies | 0 | |||||
Current derivative assets | 0 | |||||
Income taxes receivable | 0 | |||||
Assets held for sale | 0 | |||||
Prepaid expenses and other | 0 | |||||
Total current assets | (9,447) | |||||
Oil and Gas Property [Abstract] | ||||||
Proved properties | 0 | |||||
Unproved properties not being amortized | 0 | |||||
Drilling equipment | 0 | |||||
Gas gathering and processing equipment | 0 | |||||
Saltwater disposal systems | 0 | |||||
Land and building | 0 | |||||
Transportation equipment | 0 | |||||
Other | 0 | |||||
Property, plant and equipment, gross, total | 0 | |||||
Less accumulated depreciation, depletion, amortization, and impairment | 0 | |||||
Net property and equipment | 0 | |||||
Intercompany receivable | (1,048,785) | |||||
Investments | (865,252) | |||||
Right of use asset | (54) | |||||
Other assets | 0 | |||||
Total assets | (1,923,538) | |||||
Current liabilities: | ||||||
Accounts payable | (7,291) | |||||
Accrued liabilities | (2,156) | |||||
Operating Lease, Liability, Current | (6) | |||||
Current portion of long-term debt (Note 9) | 0 | |||||
Current portion of other long-term liabilities | 0 | |||||
Total current liabilities | (9,453) | |||||
Intercompany debt | (1,048,785) | |||||
Long-term debt less debt issuance costs | 0 | |||||
Non-current derivative liabilities | 0 | |||||
Long-term operating lease payments | (48) | |||||
Other long-term liabilities | 0 | |||||
Deferred income taxes | 0 | |||||
Total shareholders' equity | (865,252) | |||||
Total liabilities and shareholders' equity | (1,923,538) | |||||
Parent | ||||||
Current assets: | ||||||
Cash and cash equivalents | 503 | 403 | ||||
Accounts receivable | 2,645 | |||||
Materials and supplies | 0 | |||||
Current derivative assets | 633 | |||||
Income taxes receivable | 1,756 | |||||
Assets held for sale | 0 | |||||
Prepaid expenses and other | 2,019 | |||||
Total current assets | 7,556 | |||||
Oil and Gas Property [Abstract] | ||||||
Proved properties | 0 | |||||
Unproved properties not being amortized | 0 | |||||
Drilling equipment | 0 | |||||
Gas gathering and processing equipment | 0 | |||||
Saltwater disposal systems | 0 | |||||
Land and building | 0 | |||||
Transportation equipment | 9,712 | |||||
Other | 28,927 | |||||
Property, plant and equipment, gross, total | 38,639 | |||||
Less accumulated depreciation, depletion, amortization, and impairment | 33,794 | |||||
Net property and equipment | 4,845 | |||||
Intercompany receivable | 1,048,785 | |||||
Investments | 865,252 | |||||
Right of use asset | 46 | |||||
Other assets | 8,107 | |||||
Total assets | 1,934,591 | |||||
Current liabilities: | ||||||
Accounts payable | 12,259 | |||||
Accrued liabilities | 28,003 | |||||
Operating Lease, Liability, Current | 20 | |||||
Current portion of long-term debt (Note 9) | 108,200 | |||||
Current portion of other long-term liabilities | 3,003 | |||||
Total current liabilities | 151,485 | |||||
Intercompany debt | 0 | |||||
Long-term debt less debt issuance costs | 646,716 | |||||
Non-current derivative liabilities | 27 | |||||
Long-term operating lease payments | 25 | |||||
Other long-term liabilities | 12,553 | |||||
Deferred income taxes | 68,150 | |||||
Total shareholders' equity | 1,055,635 | |||||
Total liabilities and shareholders' equity | 1,934,591 | |||||
Combined Guarantor Subsidiaries | ||||||
Current assets: | ||||||
Cash and cash equivalents | 68 | 208 | ||||
Accounts receivable | 64,805 | |||||
Materials and supplies | 449 | |||||
Current derivative assets | 0 | |||||
Income taxes receivable | 0 | |||||
Assets held for sale | 5,908 | |||||
Prepaid expenses and other | 3,373 | |||||
Total current assets | 74,603 | |||||
Oil and Gas Property [Abstract] | ||||||
Proved properties | 6,341,582 | |||||
Unproved properties not being amortized | 252,874 | |||||
Drilling equipment | 1,295,713 | |||||
Gas gathering and processing equipment | 0 | |||||
Saltwater disposal systems | 69,692 | |||||
Land and building | 59,080 | |||||
Transportation equipment | 16,621 | |||||
Other | 29,065 | |||||
Property, plant and equipment, gross, total | 8,064,627 | |||||
Less accumulated depreciation, depletion, amortization, and impairment | 6,537,731 | |||||
Net property and equipment | 1,526,896 | |||||
Intercompany receivable | 0 | |||||
Investments | 0 | |||||
Right of use asset | 1,733 | |||||
Other assets | 9,094 | |||||
Total assets | 1,612,326 | |||||
Current liabilities: | ||||||
Accounts payable | 61,002 | |||||
Accrued liabilities | 14,024 | |||||
Operating Lease, Liability, Current | 1,009 | |||||
Current portion of long-term debt (Note 9) | 0 | |||||
Current portion of other long-term liabilities | 7,313 | |||||
Total current liabilities | 83,348 | |||||
Intercompany debt | 1,047,599 | |||||
Long-term debt less debt issuance costs | 0 | |||||
Non-current derivative liabilities | 0 | |||||
Long-term operating lease payments | 690 | |||||
Other long-term liabilities | 74,662 | |||||
Deferred income taxes | (54,437) | |||||
Total shareholders' equity | 460,464 | |||||
Total liabilities and shareholders' equity | 1,612,326 | |||||
Combined Non-Guarantor Subsidiaries | ||||||
Current assets: | ||||||
Cash and cash equivalents | 0 | $ 5,841 | ||||
Accounts receivable | 24,653 | |||||
Materials and supplies | 0 | |||||
Current derivative assets | 0 | |||||
Income taxes receivable | 0 | |||||
Assets held for sale | 0 | |||||
Prepaid expenses and other | 7,686 | |||||
Total current assets | 32,339 | |||||
Oil and Gas Property [Abstract] | ||||||
Proved properties | 0 | |||||
Unproved properties not being amortized | 0 | |||||
Drilling equipment | 0 | |||||
Gas gathering and processing equipment | 824,699 | |||||
Saltwater disposal systems | 0 | |||||
Land and building | 0 | |||||
Transportation equipment | 3,390 | |||||
Other | 0 | |||||
Property, plant and equipment, gross, total | 828,089 | |||||
Less accumulated depreciation, depletion, amortization, and impairment | 407,144 | |||||
Net property and equipment | 420,945 | |||||
Intercompany receivable | 0 | |||||
Investments | 0 | |||||
Right of use asset | 3,948 | |||||
Other assets | 9,441 | |||||
Total assets | 466,673 | |||||
Current liabilities: | ||||||
Accounts payable | 18,511 | |||||
Accrued liabilities | 6,691 | |||||
Operating Lease, Liability, Current | 2,407 | |||||
Current portion of long-term debt (Note 9) | 0 | |||||
Current portion of other long-term liabilities | 7,060 | |||||
Total current liabilities | 34,669 | |||||
Intercompany debt | 1,186 | |||||
Long-term debt less debt issuance costs | 16,500 | |||||
Non-current derivative liabilities | 0 | |||||
Long-term operating lease payments | 1,404 | |||||
Other long-term liabilities | 8,126 | |||||
Deferred income taxes | 0 | |||||
Total shareholders' equity | 404,788 | |||||
Total liabilities and shareholders' equity | $ 466,673 | |||||
[1] | Unit Corporation's consolidated total assets as of December 31, 2020 include current and long-term assets of its variable interest entity (VIE) (Superior) of $45.8 million and $247.8 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 19 – Variable Interest Entity Arrangements. |
Supplemental Condensed Consol_4
Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Balance Sheets Parenthetical) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 |
Condensed Financial Statements, Captions [Line Items] | ||
Accounts receivable, allowance for doubtful accounts | $ 3,783 | $ 2,332 |
Common stock, shares issued | 12,000,000 | 55,443,393 |
Common stock, shares authorized | 25,000,000 | 175,000,000 |
Parent | ||
Condensed Financial Statements, Captions [Line Items] | ||
Accounts receivable, allowance for doubtful accounts | $ 1,216 | |
Combined Guarantor Subsidiaries | ||
Condensed Financial Statements, Captions [Line Items] | ||
Accounts receivable, allowance for doubtful accounts | $ 1,116 |
Supplemental Condensed Consol_5
Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Operation) (Details) - USD ($) $ in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 4 Months Ended | 8 Months Ended | 12 Months Ended | ||||||||||
Sep. 30, 2020 | Aug. 31, 2020 | Dec. 31, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||||
Revenues | $ 32,846 | $ 65,574 | $ 100,682 | $ 89,007 | $ 122,376 | $ 164,358 | $ 155,439 | $ 165,146 | $ 189,691 | $ 276,957 | $ 674,634 | |||||
Expenses | ||||||||||||||||
Operating costs | $ 81,277 | 237,546 | 384,728 | |||||||||||||
Depreciation, depletion, and amortization | 27,962 | 115,496 | 275,573 | |||||||||||||
Impairments | 26,063 | [1] | 867,814 | [2] | 625,716 | [3] | ||||||||||
Loss on abandonment of assets | 0 | 18,733 | 0 | |||||||||||||
General and administrative | 6,702 | 42,766 | 38,246 | |||||||||||||
(Gain) loss on disposition of assets | (619) | (89) | 3,502 | |||||||||||||
Total operating expenses | 141,385 | 1,282,266 | 1,327,765 | |||||||||||||
Income (loss) from operations | (7,857) | (1,005,309) | (653,131) | |||||||||||||
Interest, net | (3,275) | (22,824) | (37,012) | |||||||||||||
Write off of Deferred Debt Issuance Cost | 0 | (2,426) | 0 | |||||||||||||
Gain (loss) on derivatives | (985) | (10,704) | 4,225 | |||||||||||||
Reorganization Items | (2,273) | 133,975 | 0 | |||||||||||||
Other | 100 | 2,034 | (236) | |||||||||||||
Income (loss) before income taxes | (14,290) | (905,254) | (686,154) | |||||||||||||
Income tax benefit | (302) | (14,630) | (132,326) | |||||||||||||
Equity in net earnings from investment in subsidiaries, net of taxes | 0 | 0 | ||||||||||||||
Net loss | (13,988) | (890,624) | (553,828) | |||||||||||||
Less: net income attributable to non-controlling interest | 4,152 | 40,388 | 51 | |||||||||||||
Net income (loss) attributable to Unit Corporation | $ (8,968) | $ 55,131 | $ (9,172) | $ (215,649) | $ (770,494) | $ (334,980) | [4] | $ (206,886) | $ (8,509) | $ (3,504) | $ (18,140) | (931,012) | (553,879) | |||
Consolidating Adjustments | ||||||||||||||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||||
Revenues | (14,536) | (47,485) | ||||||||||||||
Expenses | ||||||||||||||||
Operating costs | (14,537) | (47,485) | ||||||||||||||
Depreciation, depletion, and amortization | 0 | 0 | ||||||||||||||
Impairments | 0 | 0 | ||||||||||||||
Loss on abandonment of assets | 0 | |||||||||||||||
General and administrative | 0 | 0 | ||||||||||||||
(Gain) loss on disposition of assets | 0 | 0 | ||||||||||||||
Total operating expenses | (14,537) | (47,485) | ||||||||||||||
Income (loss) from operations | 1 | 0 | ||||||||||||||
Interest, net | 0 | 0 | ||||||||||||||
Write off of Deferred Debt Issuance Cost | 0 | |||||||||||||||
Gain (loss) on derivatives | 0 | 0 | ||||||||||||||
Reorganization Items | 0 | |||||||||||||||
Other | 0 | 0 | ||||||||||||||
Income (loss) before income taxes | 1 | 0 | ||||||||||||||
Income tax benefit | 0 | 0 | ||||||||||||||
Equity in net earnings from investment in subsidiaries, net of taxes | 1,241,120 | 508,439 | ||||||||||||||
Net loss | 1,241,121 | 508,439 | ||||||||||||||
Less: net income attributable to non-controlling interest | (40,388) | (51) | ||||||||||||||
Net income (loss) attributable to Unit Corporation | 1,281,509 | 508,490 | ||||||||||||||
Parent | ||||||||||||||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||||
Revenues | 0 | 0 | ||||||||||||||
Expenses | ||||||||||||||||
Operating costs | 0 | 0 | ||||||||||||||
Depreciation, depletion, and amortization | 1,819 | 7,707 | ||||||||||||||
Impairments | 0 | 0 | ||||||||||||||
Loss on abandonment of assets | 0 | |||||||||||||||
General and administrative | 0 | 0 | ||||||||||||||
(Gain) loss on disposition of assets | 1,479 | (11) | ||||||||||||||
Total operating expenses | 3,298 | 7,696 | ||||||||||||||
Income (loss) from operations | (3,298) | (7,696) | ||||||||||||||
Interest, net | (20,936) | (35,466) | ||||||||||||||
Write off of Deferred Debt Issuance Cost | (2,426) | |||||||||||||||
Gain (loss) on derivatives | (10,704) | 4,225 | ||||||||||||||
Reorganization Items | 373,151 | |||||||||||||||
Other | 79 | 786 | ||||||||||||||
Income (loss) before income taxes | 335,866 | (38,151) | ||||||||||||||
Income tax benefit | (14,630) | 7,238 | ||||||||||||||
Equity in net earnings from investment in subsidiaries, net of taxes | (1,241,120) | (508,439) | ||||||||||||||
Net loss | (890,624) | (553,828) | ||||||||||||||
Less: net income attributable to non-controlling interest | 40,388 | 51 | ||||||||||||||
Net income (loss) attributable to Unit Corporation | (931,012) | (553,879) | ||||||||||||||
Combined Guarantor Subsidiaries | ||||||||||||||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||||
Revenues | 176,962 | 494,180 | ||||||||||||||
Expenses | ||||||||||||||||
Operating costs | 171,476 | 256,024 | ||||||||||||||
Depreciation, depletion, and amortization | 84,306 | 220,203 | ||||||||||||||
Impairments | 803,852 | 622,676 | ||||||||||||||
Loss on abandonment of assets | 18,733 | |||||||||||||||
General and administrative | 42,766 | 38,246 | ||||||||||||||
(Gain) loss on disposition of assets | (1,550) | 3,673 | ||||||||||||||
Total operating expenses | 1,119,583 | 1,140,822 | ||||||||||||||
Income (loss) from operations | (942,621) | (646,642) | ||||||||||||||
Interest, net | 0 | 0 | ||||||||||||||
Write off of Deferred Debt Issuance Cost | 0 | |||||||||||||||
Gain (loss) on derivatives | 0 | 0 | ||||||||||||||
Reorganization Items | (168,160) | |||||||||||||||
Other | 1,906 | (1,086) | ||||||||||||||
Income (loss) before income taxes | (1,108,875) | (647,728) | ||||||||||||||
Income tax benefit | 0 | (139,564) | ||||||||||||||
Equity in net earnings from investment in subsidiaries, net of taxes | 0 | 0 | ||||||||||||||
Net loss | (1,108,875) | (508,164) | ||||||||||||||
Less: net income attributable to non-controlling interest | 0 | 0 | ||||||||||||||
Net income (loss) attributable to Unit Corporation | (1,108,875) | (508,164) | ||||||||||||||
Combined Non-Guarantor Subsidiaries | ||||||||||||||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||||
Revenues | 114,531 | 227,939 | ||||||||||||||
Expenses | ||||||||||||||||
Operating costs | 80,607 | 176,189 | ||||||||||||||
Depreciation, depletion, and amortization | 29,371 | 47,663 | ||||||||||||||
Impairments | 63,962 | 3,040 | ||||||||||||||
Loss on abandonment of assets | 0 | |||||||||||||||
General and administrative | 0 | 0 | ||||||||||||||
(Gain) loss on disposition of assets | (18) | (160) | ||||||||||||||
Total operating expenses | 173,922 | 226,732 | ||||||||||||||
Income (loss) from operations | (59,391) | 1,207 | ||||||||||||||
Interest, net | (1,888) | (1,546) | ||||||||||||||
Write off of Deferred Debt Issuance Cost | 0 | |||||||||||||||
Gain (loss) on derivatives | 0 | 0 | ||||||||||||||
Reorganization Items | (71,016) | |||||||||||||||
Other | 49 | 64 | ||||||||||||||
Income (loss) before income taxes | (132,246) | (275) | ||||||||||||||
Income tax benefit | 0 | 0 | ||||||||||||||
Equity in net earnings from investment in subsidiaries, net of taxes | 0 | 0 | ||||||||||||||
Net loss | (132,246) | (275) | ||||||||||||||
Less: net income attributable to non-controlling interest | 40,388 | 51 | ||||||||||||||
Net income (loss) attributable to Unit Corporation | $ (172,634) | $ (326) | ||||||||||||||
[1] | During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax | |||||||||||||||
[2] | During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups. | |||||||||||||||
[3] | We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax). | |||||||||||||||
[4] | During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax. 4. During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax. 5. During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets. 6. During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax. 7. During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net. |
Supplemental Condensed Consol_6
Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Condensed Financial Statements, Captions [Line Items] | |||
Net loss | $ (13,988) | $ (890,624) | $ (553,828) |
Reclassification adjustment for write-down of securities, net of tax | 0 | 0 | 481 |
Unrealized loss on securities, tax | (47) | ||
Reclassification Adjustment from AOCI for Write-down of Securities, Tax | 0 | 0 | (47) |
Comprehensive income (loss) | (13,988) | (890,624) | (553,347) |
Less: Comprehensive income attributable to non-controlling interest | 4,152 | 40,388 | 51 |
Comprehensive income (loss) attributable to Unit Corporation | $ (18,140) | (931,012) | (553,398) |
Consolidating Adjustments | |||
Condensed Financial Statements, Captions [Line Items] | |||
Net loss | 1,241,121 | 508,439 | |
Reclassification adjustment for write-down of securities, net of tax | 0 | 0 | |
Comprehensive income (loss) | 1,241,121 | 508,439 | |
Less: Comprehensive income attributable to non-controlling interest | (40,388) | (51) | |
Comprehensive income (loss) attributable to Unit Corporation | 1,281,509 | 508,490 | |
Parent | |||
Condensed Financial Statements, Captions [Line Items] | |||
Net loss | (890,624) | (553,828) | |
Reclassification adjustment for write-down of securities, net of tax | 0 | 0 | |
Comprehensive income (loss) | (890,624) | (553,828) | |
Less: Comprehensive income attributable to non-controlling interest | 40,388 | 51 | |
Comprehensive income (loss) attributable to Unit Corporation | (931,012) | (553,879) | |
Combined Guarantor Subsidiaries | |||
Condensed Financial Statements, Captions [Line Items] | |||
Net loss | (1,108,875) | (508,164) | |
Reclassification adjustment for write-down of securities, net of tax | 0 | 481 | |
Unrealized loss on securities, tax | (47) | ||
Comprehensive income (loss) | (1,108,875) | (507,683) | |
Less: Comprehensive income attributable to non-controlling interest | 0 | 0 | |
Comprehensive income (loss) attributable to Unit Corporation | (1,108,875) | (507,683) | |
Combined Non-Guarantor Subsidiaries | |||
Condensed Financial Statements, Captions [Line Items] | |||
Net loss | (132,246) | (275) | |
Reclassification adjustment for write-down of securities, net of tax | 0 | 0 | |
Comprehensive income (loss) | (132,246) | (275) | |
Less: Comprehensive income attributable to non-controlling interest | 40,388 | 51 | |
Comprehensive income (loss) attributable to Unit Corporation | $ (172,634) | $ (326) |
Supplemental Condensed Consol_7
Supplemental Condensed Consolidated Financial Information (Condensed Consolidating Statements of Cash Flow) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
OPERATING ACTIVITIES: | |||
Net cash provided by (used in) operating activities | $ 29,807 | $ 44,956 | $ 269,396 |
INVESTING ACTIVITIES: | |||
Capital expeditures | (4,057) | (25,775) | (406,665) |
Producing property and other oil and natural gas acquisitions | 0 | (382) | (3,653) |
Other acquisitions | 0 | 0 | 16,109 |
Proceeds from disposition of property and equipment | 1,799 | 6,018 | 31,864 |
Net cash provided by (used in) investing activities | (2,258) | (20,139) | (394,563) |
FINANCING ACTIVITIES: | |||
Borrowings under line of credit | 0 | 87,400 | 493,500 |
Payments under line of credit | (49,000) | (64,100) | (368,800) |
Intercompany borrowings (advances), net | 0 | 0 | |
Net payments on finance leases | (1,406) | (2,757) | (4,001) |
Employee taxes paid by withholding shares | 0 | (43) | (4,158) |
Distributions to non-controlling interest | 0 | 0 | (918) |
Proceeds from investments of non-contolling interests | 0 | 0 | 0 |
Transaction costs associated with sale of non-controlling interest | 0 | 0 | 0 |
Bank overdrafts | 2,631 | (8,733) | 3,663 |
Net cash provided by (used in) financing activities | (47,775) | 7,552 | 119,286 |
Net increase (decrease) in cash and cash equivalents | (20,226) | 32,369 | (5,881) |
Cash, restricted cash, cash equivalents, beginning of year | 32,940 | 571 | 6,452 |
Cash, restricted cash, cash equivalents, end of year | 12,714 | 32,940 | 571 |
DIP financing costs | 0 | (990) | 0 |
Exit facility financing costs | 0 | (3,225) | 0 |
Consolidating Adjustments | |||
OPERATING ACTIVITIES: | |||
Net cash provided by (used in) operating activities | 136,858 | 12,338 | |
INVESTING ACTIVITIES: | |||
Capital expeditures | 0 | 0 | |
Producing property and other oil and natural gas acquisitions | 0 | 0 | |
Other acquisitions | 0 | ||
Proceeds from disposition of property and equipment | 0 | 0 | |
Net cash provided by (used in) investing activities | 0 | 0 | |
FINANCING ACTIVITIES: | |||
Borrowings under line of credit | 0 | 0 | |
Payments under line of credit | 0 | 0 | |
Intercompany borrowings (advances), net | (136,858) | (12,338) | |
Net payments on finance leases | 0 | 0 | |
Employee taxes paid by withholding shares | 0 | 0 | |
Distributions to non-controlling interest | 0 | ||
Bank overdrafts | 0 | 0 | |
Net cash provided by (used in) financing activities | (136,858) | (12,338) | |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | |
Cash, restricted cash, cash equivalents, beginning of year | 0 | 0 | |
Cash, restricted cash, cash equivalents, end of year | 0 | 0 | |
DIP financing costs | 0 | ||
Exit facility financing costs | 0 | ||
Parent | |||
OPERATING ACTIVITIES: | |||
Net cash provided by (used in) operating activities | (207,593) | (9,681) | |
INVESTING ACTIVITIES: | |||
Capital expeditures | (986) | 65 | |
Producing property and other oil and natural gas acquisitions | 0 | 0 | |
Other acquisitions | 0 | ||
Proceeds from disposition of property and equipment | 1,169 | 11 | |
Net cash provided by (used in) investing activities | 183 | 76 | |
FINANCING ACTIVITIES: | |||
Borrowings under line of credit | 55,300 | 400,600 | |
Payments under line of credit | (31,500) | (292,400) | |
Intercompany borrowings (advances), net | 210,398 | (97,455) | |
Net payments on finance leases | 0 | 0 | |
Employee taxes paid by withholding shares | (43) | (4,158) | |
Distributions to non-controlling interest | 919 | ||
Bank overdrafts | (7,269) | 2,199 | |
Net cash provided by (used in) financing activities | 222,671 | 9,705 | |
Net increase (decrease) in cash and cash equivalents | 15,261 | 100 | |
Cash, restricted cash, cash equivalents, beginning of year | 15,764 | 503 | |
Cash, restricted cash, cash equivalents, end of year | 15,764 | 503 | |
Combined Guarantor Subsidiaries | |||
OPERATING ACTIVITIES: | |||
Net cash provided by (used in) operating activities | 82,769 | 217,883 | |
INVESTING ACTIVITIES: | |||
Capital expeditures | (14,585) | (355,258) | |
Producing property and other oil and natural gas acquisitions | (382) | (3,653) | |
Other acquisitions | 0 | ||
Proceeds from disposition of property and equipment | 4,772 | 31,153 | |
Net cash provided by (used in) investing activities | (10,195) | (327,758) | |
FINANCING ACTIVITIES: | |||
Borrowings under line of credit | 0 | 0 | |
Payments under line of credit | 0 | 0 | |
Intercompany borrowings (advances), net | (72,642) | 109,735 | |
Net payments on finance leases | 0 | 0 | |
Employee taxes paid by withholding shares | 0 | 0 | |
Distributions to non-controlling interest | 0 | ||
Bank overdrafts | 0 | 0 | |
Net cash provided by (used in) financing activities | (72,642) | 109,735 | |
Net increase (decrease) in cash and cash equivalents | (68) | (140) | |
Cash, restricted cash, cash equivalents, beginning of year | 0 | 68 | |
Cash, restricted cash, cash equivalents, end of year | 0 | 68 | |
DIP financing costs | 0 | ||
Exit facility financing costs | 0 | ||
Combined Non-Guarantor Subsidiaries | |||
OPERATING ACTIVITIES: | |||
Net cash provided by (used in) operating activities | 32,922 | 48,856 | |
INVESTING ACTIVITIES: | |||
Capital expeditures | (10,204) | (51,472) | |
Producing property and other oil and natural gas acquisitions | 0 | 0 | |
Other acquisitions | 16,109 | ||
Proceeds from disposition of property and equipment | 77 | 700 | |
Net cash provided by (used in) investing activities | (10,127) | (66,881) | |
FINANCING ACTIVITIES: | |||
Borrowings under line of credit | 32,100 | 92,900 | |
Payments under line of credit | (32,600) | (76,400) | |
Intercompany borrowings (advances), net | (898) | 58 | |
Net payments on finance leases | (2,757) | (4,001) | |
Employee taxes paid by withholding shares | 0 | 0 | |
Distributions to non-controlling interest | (1,837) | ||
Bank overdrafts | (1,464) | 1,464 | |
Net cash provided by (used in) financing activities | (5,619) | 12,184 | |
Net increase (decrease) in cash and cash equivalents | 17,176 | (5,841) | |
Cash, restricted cash, cash equivalents, beginning of year | $ 17,176 | 0 | |
Cash, restricted cash, cash equivalents, end of year | 17,176 | $ 0 | |
DIP financing costs | 0 | ||
Exit facility financing costs | 0 | ||
Parent Company [Member] | |||
FINANCING ACTIVITIES: | |||
DIP financing costs | (990) | ||
Exit facility financing costs | $ (3,225) |
Supplemental Oil And Gas Disc_3
Supplemental Oil And Gas Disclosures (Schedule Of Capitalized Costs And Costs Incurred On Oil And Gas Properties) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | Sep. 01, 2020 | |
Capitalized costs: | ||||
Proved properties | $ 238,581 | $ 6,539,816 | $ 6,341,582 | $ 238,284 |
Unproved properties not being amortized | 1,591 | 30,205 | 252,874 | $ 0 |
Capitalized costs gross | 240,172 | 6,594,456 | ||
Accumulated depreciation, depletion, amortization, and impairment | (40,806) | (5,846,177) | ||
Net capitalized costs | 199,366 | 748,279 | ||
Costs incurred: | ||||
Unproved properties acquired | 26 | 2,373 | 34,668 | |
Proved properties acquired | 0 | 382 | 3,653 | |
Exploration | 0 | 0 | 16,480 | |
Development | 3,992 | 6,440 | 211,443 | |
Asset retirement obligation | (1,702) | (29,189) | 76 | |
Total costs incurred | $ 2,316 | $ (19,994) | $ 266,320 |
Supplemental Oil And Gas Disc_4
Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended | |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | Sep. 01, 2020 | |
Unproved properties acquired and wells in progress | $ 1,591 | $ 30,205 | $ 252,874 | $ 0 |
Costs Incurred, Acquisition of Unproved Oil and Gas Properties | 26 | 2,373 | 34,668 | |
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | 0 | 382 | 3,653 | |
Costs Incurred, Exploration Costs | 0 | 0 | 16,480 | |
Costs Incurred, Development Costs | 3,992 | 6,440 | 211,443 | |
Asset retirement obligation | (1,702) | (29,189) | 76 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities | $ 2,316 | $ (19,994) | $ 266,320 |
Supplemental Oil And Gas Disc_5
Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) - USD ($) $ in Thousands | 4 Months Ended | 8 Months Ended | 12 Months Ended |
Dec. 31, 2020 | Aug. 31, 2020 | Dec. 31, 2019 | |
Supplemental Oil and Gas Disclosures [Abstract] | |||
Revenues | $ 55,272 | $ 96,033 | $ 314,925 |
Production costs | (20,510) | (46,633) | (116,051) |
Depreciation, depletion, amortization, and impairment | (40,840) | (461,901) | (727,529) |
Results of operations, income before income taxes | (6,078) | (412,501) | (528,655) |
Income tax (expense) benefit | 128 | 6,698 | 101,952 |
Results of operations for producing activities (excluding corporate overhead and financing costs) | $ (5,950) | $ (405,803) | $ (426,703) |
Supplemental Oil And Gas Disc_6
Supplemental Oil And Gas Disclosures (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) bbl in Thousands, Mcf in Thousands, MBoe in Thousands | 8 Months Ended | 12 Months Ended |
Aug. 31, 2020MBoebblMcf | Dec. 31, 2019MBoeMcfbbl | |
Proved developed and undeveloped reserves: | ||
Beginning of year (MBoe) | MBoe | 71,924 | 159,681 |
Revision of previous estimate (MBoe) | MBoe | (12,870) | (68,366) |
Extension and discovery (MBoe) | MBoe | 39 | 3,015 |
Infill reserves in existing proved fields (MBoe) | MBoe | 238 | 1,506 |
Purchase of mineral in place (MBoe) | MBoe | 112 | 503 |
Production (MBoe) | MBoe | (11,891) | (16,825) |
Sales (MBoe) | MBoe | (11) | (7,590) |
End of year (MBoe) | MBoe | 47,541 | 71,924 |
Proved developed reserves: | ||
Beginning of year (MBoe) | MBoe | 71,924 | |
End of year (MBoe) | MBoe | 47,541 | 71,924 |
Proved undeveloped reserves | ||
Beginning of year (MBoe) | MBoe | 0 | |
End of year (MBoe) | MBoe | 0 | 0 |
Oil (bbls) | ||
Proved developed and undeveloped reserves: | ||
Beginning of year | 12,196 | 22,558 |
Revision of previous estimates | (1,909) | (8,263) |
Extensions and discoveries | 8 | 703 |
Infill reserves in existing proved fields | 97 | 271 |
Purchases of minerals in place | 62 | 183 |
Production | (2,186) | (3,208) |
Sales | (1) | (48) |
End of year | 8,267 | 12,196 |
Proved developed reserves: | ||
Beginning of year | 12,196 | |
End of year | 8,267 | 12,196 |
Proved undeveloped reserves | ||
Beginning of year | 0 | |
End of year | 0 | 0 |
Natural Gas Liquids (bbls) | ||
Proved developed and undeveloped reserves: | ||
Beginning of year | 23,030 | 47,796 |
Revision of previous estimates | (4,477) | (20,961) |
Extensions and discoveries | 13 | 845 |
Infill reserves in existing proved fields | 66 | 434 |
Purchases of minerals in place | 20 | 101 |
Production | (3,444) | (4,773) |
Sales | 0 | (412) |
End of year | 15,208 | 23,030 |
Proved developed reserves: | ||
Beginning of year | 23,030 | |
End of year | 15,208 | 23,030 |
Proved undeveloped reserves | ||
Beginning of year | 0 | |
End of year | 0 | 0 |
Natural gas (Mcf) | ||
Proved developed and undeveloped reserves: | ||
Beginning of year | Mcf | 220,187 | 535,963 |
Revision of previous estimates | Mcf | (38,901) | (234,852) |
Extensions and discoveries | Mcf | 110 | 8,798 |
Infill reserves in existing proved fields | Mcf | 452 | 4,806 |
Purchases of minerals in place | Mcf | 172 | 1,316 |
Production | Mcf | (37,567) | (53,064) |
Sales | Mcf | (62) | (42,780) |
End of year | Mcf | 144,391 | 220,187 |
Proved developed reserves: | ||
Beginning of year | Mcf | 220,187 | |
End of year | Mcf | 144,391 | 220,187 |
Proved undeveloped reserves | ||
Beginning of year | Mcf | 0 | |
End of year | Mcf | 0 | 0 |
Supplemental Oil And Gas Disc_7
Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) - USD ($) $ in Thousands | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | |||
Future cash flows | $ 698,685 | $ 1,386,777 | |
Future production costs | (416,095) | (698,357) | |
Future development costs | 0 | 0 | |
Future income tax expenses | (39) | (321) | |
Future net cash flows | 282,551 | 688,099 | |
10% annual discount for estimated timing of cash flows | (89,530) | (226,390) | |
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves | $ 193,021 | $ 461,709 | $ 983,678 |
Supplemental Oil And Gas Disc_8
Supplemental Oil And Gas Disclosures (Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Reserve Quantities [Line Items] | ||
Sales and transfers of oil and natural gas produced, net of production costs | $ (84,163) | $ (200,233) |
Net changes in prices and production costs | (165,978) | (508,066) |
Revisions in quantity estimates and changes in production timing | (50,979) | (338,994) |
Extensions, discoveries, and improved recovery, less related costs | 2,827 | 53,123 |
Changes in estimated future development costs | 0 | 311,190 |
Previously estimated cost incurred during the period | 0 | 64,362 |
Purchases of minerals in place | 852 | 6,416 |
Sales of minerals in place | (46) | (25,813) |
Accretion of discount | 46,203 | 110,571 |
Net change in income taxes | 282 | 121,708 |
Other-net | (17,686) | (116,233) |
Net change | (268,688) | (521,969) |
Beginning of year | 461,709 | 983,678 |
End of year | $ 193,021 | $ 461,709 |
Supplemental Oil and Gas Disc_9
Supplemental Oil and Gas Disclosures (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2020$ / Unit | |
Oil (bbls) | |
Oil and Gas, Average Sale Price | 39.57 |
Natural Gas Liquids (bbls) | |
Oil and Gas, Average Sale Price | 18.70 |
Natural gas (Mcf) | |
Oil and Gas, Average Sale Price | 1.98 |
Schedule II - Valuation And Q_3
Schedule II - Valuation And Qualifying Accounts And Reserves Valuation and Qualifying Accounts and Reserves (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2020 | Dec. 31, 2019 | |
Valuation and Qualifying Accounts Disclosure [Line Items] | ||
Balance at beginning of period | $ 2,332 | $ 2,531 |
Additions charged to costs and expenses | 3,155 | 527 |
Deductions and net write-offs | (1,704) | (726) |
Balance at end of period | $ 3,783 | $ 2,332 |
Uncategorized Items - unt-20201
Label | Element | Value |
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | $ 71,020,000 |
AOCI Attributable to Parent [Member] | ||
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | 0 |
Noncontrolling Interest [Member] | ||
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | 0 |
Additional Paid-in Capital [Member] | ||
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | (650,153,000) |
Common Stock [Member] | ||
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | (10,704,000) |
Retained Earnings [Member] | ||
Temporary Equity, Elimination as Part of Reorganization | us-gaap_TemporaryEquityEliminationAsPartofReorganization | $ 731,877,000 |