DENBURY INC, 10-K filed on 2/25/2022
Annual Report
v3.22.0.1
Document and Entity Information - USD ($)
12 Months Ended
Dec. 31, 2021
Jan. 31, 2022
Jun. 30, 2021
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2021    
Document Transition Report false    
Entity File Number 001-12935    
Entity Registrant Name DENBURY INC.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 20-0467835    
Entity Address, Address Line One 5851 Legacy Circle,    
Entity Address, City or Town Plano,    
Entity Address, State or Province TX    
Entity Address, Postal Zip Code 75024    
City Area Code (972)    
Local Phone Number 673-2000    
Title of 12(b) Security Common Stock $.001 Par Value    
Trading Symbol DEN    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
Auditor Attestation Flag true    
Entity Shell Company false    
Entity Bankruptcy Proceedings, Reporting Current true    
Entity Public Float     $ 3,839,619,307
Entity Common Stock, Shares Outstanding   50,199,676  
Documents Incorporated by Reference 1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 26, 2022.    
Entity Central Index Key 0000945764    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2021    
Document Fiscal Period Focus FY    
Amendment Flag false    
Auditor Name PricewaterhouseCoopers LLP    
Auditor Location Dallas, TX    
Auditor Firm ID 238    
v3.22.0.1
Consolidated Balance Sheets - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Current assets    
Cash and cash equivalents $ 3,671 $ 518
Restricted cash 0 1,000
Accrued production receivable 143,365 91,421
Trade and other receivables, net 19,270 19,682
Derivative assets 0 187
Prepaids 9,099 14,038
Total current assets 175,405 126,846
Oil and natural gas properties (using full cost accounting)    
Proved properties 1,109,011 851,208
Unevaluated properties 112,169 85,304
CO2 properties 183,369 188,288
Pipelines 224,394 133,485
Other property and equipment 93,950 86,610
Less accumulated depletion, depreciation, amortization and impairment (181,393) (41,095)
Net property and equipment 1,541,500 1,303,800
Operating lease right-of-use assets 19,502 20,342
Intangible asset, net 88,248 97,362
Other assets 78,298 86,408
Total assets 1,902,953 1,634,758
Current liabilities    
Accounts payable and accrued liabilities 191,598 112,671
Oil and gas production payable 75,899 49,165
Derivative liabilities 134,509 53,865
Current maturities of long-term debt 0 68,008
Operating lease liabilities 4,677 1,350
Total current liabilities 406,683 285,059
Liabilities, Noncurrent [Abstract]    
Long-term debt, net of current portion 35,000 70,000
Asset retirement obligations 284,238 179,338
Derivative liabilities 0 5,087
Deferred tax liabilities, net 1,638 1,274
Operating lease liabilities 17,094 19,460
Other liabilities 22,910 20,872
Total long-term liabilities 360,880 296,031
Commitments and contingencies (Note 14)
Stockholders' equity    
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding 0 0
Common stock, $.001 par value, 250,000,000 shares authorized; 50,193,656 and 49,999,999 shares issued, respectively 50 50
Paid-in capital in excess of par 1,129,996 1,104,276
Retained earnings (accumulated deficit) 5,344 (50,658)
Total stockholders' equity 1,135,390 1,053,668
Total liabilities and stockholders' equity $ 1,902,953 $ 1,634,758
v3.22.0.1
Consolidated Balance Sheets (Parenthetical) - $ / shares
Dec. 31, 2021
Dec. 31, 2020
Stockholders' equity    
Preferred stock, par value $ 0.001 $ 0.001
Preferred stock, shares authorized 50,000,000 50,000,000
Preferred stock, shares issued 0 0
Preferred stock, shares outstanding 0 0
Common stock, par value $ 0.001 $ 0.001
Common stock, shares authorized 250,000,000 250,000,000
Common stock, shares issued 50,193,656 49,999,999
Treasury stock, shares 0 0
v3.22.0.1
Consolidated Statements of Operations - USD ($)
shares in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Revenues and other income $ 220,600,000 $ 530,112,000 $ 1,258,160,000 $ 1,274,883,000
Expenses        
Taxes other than income 16,584,000 43,531,000 91,390,000 93,752,000
General and administrative expenses 19,470,000 48,522,000 79,258,000 83,029,000
Interest, net of amounts capitalized of $4,585, $1,261, $22,885 and $36,671, respectively 1,815,000 48,267,000 4,147,000 81,632,000
Depletion, depreciation, and amortization 45,812,000 188,593,000 150,640,000 233,816,000
Commodity derivatives expense (income) 61,902,000 (102,032,000) 352,984,000 70,078,000
Gain on debt extinguishment 0 (18,994,000) 0 (155,998,000)
Write-down of oil and natural gas properties 1,006,000 996,658,000 14,377,000 0
Reorganization items, net 0 849,980,000 0 0
Other expenses 8,072,000 35,868,000 10,816,000 11,187,000
Total expenses 273,784,000 2,378,819,000 1,201,391,000 953,572,000
Income (loss) before income taxes (53,184,000) (1,848,707,000) 56,769,000 321,311,000
Income tax provision (benefit) (2,526,000) (416,129,000) 767,000 104,352,000
Net income (loss) $ (50,658,000) $ (1,432,578,000) $ 56,002,000 $ 216,959,000
Net income (loss) per common share        
Basic $ (1.01) $ (2.89) $ 1.10 $ 0.47
Diluted $ (1.01) $ (2.89) $ 1.04 $ 0.45
Weighted average common shares outstanding        
Basic 50,000 495,560 50,918 459,524
Diluted 50,000 495,560 53,818 510,341
Other income        
Revenues and other income $ 4,697,000 $ 8,419,000 $ 15,288,000 $ 14,523,000
Transportation and marketing        
Operating expenses 10,595,000 27,164,000 28,817,000 41,810,000
Oil, natural gas, and related product sales        
Revenues and other income 201,108,000 492,101,000 1,159,955,000 1,212,020,000
Operating expenses 101,234,000 250,271,000 424,550,000 477,220,000
CO2        
Revenues and other income 9,419,000 21,049,000 44,175,000 34,142,000
Operating expenses 1,976,000 2,592,000 6,678,000 2,922,000
Oil marketing        
Revenues and other income 5,376,000 8,543,000 38,742,000 14,198,000
Operating expenses $ 5,318,000 $ 8,399,000 $ 37,734,000 $ 14,124,000
v3.22.0.1
Consolidated Statements of Operations (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Expenses        
Capitalized interest $ 1,261 $ 22,885 $ 4,585 $ 36,671
v3.22.0.1
Consolidated Statements of Cash Flows - USD ($)
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Cash flows from operating activities        
Net income (loss) $ (50,658,000) $ (1,432,578,000) $ 56,002,000 $ 216,959,000
Adjustments to reconcile net income (loss) to cash flows from operating activities        
Noncash reorganization items, net 0 810,909,000 0 0
Depletion, depreciation, and amortization 45,812,000 188,593,000 150,640,000 233,816,000
Write-down of oil and natural gas properties 1,006,000 996,658,000 14,377,000 0
Deferred income taxes (2,556,000) (408,869,000) 364,000 100,471,000
Stock-based compensation 8,212,000 4,111,000 25,322,000 12,470,000
Commodity derivatives expense (income) 61,902,000 (102,032,000) 352,984,000 70,078,000
Receipt (payment) on settlements of commodity derivatives 21,089,000 81,396,000 (277,240,000) 23,606,000
Gain on debt extinguishment 0 (18,994,000) 0 (155,998,000)
Debt issuance costs and discounts 799,000 11,571,000 2,740,000 12,303,000
Gain from asset sales and other (3,546,000) (6,723,000) (10,609,000) (8,504,000)
Other, net 1,197,000 7,162,000 (2,465,000) (92,000)
Changes in assets and liabilities, net of effects from acquisitions        
Accrued production receivable 21,411,000 26,575,000 (51,944,000) (13,619,000)
Trade and other receivables 15,567,000 (22,343,000) (284,000) 9,379,000
Other current and long-term assets (1,795,000) 743,000 10,390,000 7,629,000
Accounts payable and accrued liabilities (67,167,000) (16,102,000) 28,500,000 (3,275,000)
Oil and natural gas production payable (6,912,000) (6,792,000) 29,351,000 2,170,000
Other liabilities (4,035,000) 123,000 (10,970,000) (13,250,000)
Net cash provided by operating activities 40,326,000 113,408,000 317,158,000 494,143,000
Cash flows from investing activities        
Oil and natural gas capital expenditures (17,964,000) (99,582,000) (150,911,000) (262,005,000)
Acquisitions of oil and natural gas properties 82,000 0 10,979,000 79,000
Pipeline capital expenditures (618,000) (11,601,000) (69,223,000) (27,319,000)
Net proceeds from sales of oil and natural gas properties and equipment 938,000 41,322,000 19,053,000 10,196,000
Other 15,842,000 12,747,000 9,128,000 9,515,000
Net cash used in investing activities (1,884,000) (57,114,000) (202,932,000) (269,692,000)
Cash flows from financing activities        
Bank repayments (190,000,000) (551,000,000) (933,000,000) (925,791,000)
Bank borrowings 120,000,000 691,000,000 898,000,000 925,791,000
Interest payments treated as a reduction of debt 0 (46,417,000) 0 (85,303,000)
Cash paid in conjunction with debt exchange 0 0 0 (136,427,000)
Cash paid in conjunction with debt repurchases 0 (14,171,000) 0 0
Costs of debt financing (8,000) (12,482,000) 0 (11,065,000)
Pipeline financing and capital lease debt repayments (22,938,000) (51,792,000) (68,008,000) (13,908,000)
Other 1,638,000 (9,363,000) (3,122,000) 348,000
Net cash provided by (used in) financing activities (91,308,000) 5,775,000 (106,130,000) (246,355,000)
Net increase (decrease) in cash, cash equivalents, and restricted cash (52,866,000) 62,069,000 8,096,000 (21,904,000)
Cash, cash equivalents, and restricted cash at beginning of period 95,114,000 33,045,000 42,248,000 54,949,000
Cash, cash equivalents, and restricted cash at end of period $ 42,248,000 $ 95,114,000 $ 50,344,000 $ 33,045,000
v3.22.0.1
Consolidated Statements of Changes in Stockholders' Equity - USD ($)
$ in Thousands
Total
Common Stock ($.001 Par Value)
Paid-In Capital in Excess of Par
Retained Earnings (Accumulated Deficit)
Treasury Stock (at cost)
Beginning balance, shares at Dec. 31, 2018   462,355,725     1,941,749
Beginning balance at Dec. 31, 2018 $ 1,141,777 $ 462 $ 2,685,211 $ (1,533,112) $ (10,784)
Issued pursuant to stock compensation plans, shares   9,315,016      
Issued pursuant to stock compensation plans, value   $ 9 (9)    
Issued pursuant to directors' compensation plan, shares   97,537      
Issuance of new shares, shares   36,297,217     (1,990,000)
Issuance of new shares, value 39,555 $ 37 37,409 (5,161) $ 7,270
Stock-based compensation, value 16,488   16,488    
Issued pursuant to notes conversion, value 0        
Tax withholding for stock compensation plans, shares         1,701,022
Tax withholding for stock compensation plans, value (2,520)       $ (2,520)
Net income (loss) 216,959     216,959  
Ending balance, shares at Dec. 31, 2019   508,065,495     1,652,771
Ending balance at Dec. 31, 2019 1,412,259 $ 508 2,739,099 (1,321,314) $ (6,034)
Issued pursuant to stock compensation plans, shares   312,516      
Issued pursuant to directors' compensation plan, shares   37,367      
Issuance of new shares, shares   49,999,999      
Issuance of new shares, value 1,095,419 $ 50 1,095,369    
Stock-based compensation, value 14,317   14,317    
Issued pursuant to notes conversion, shares   7,372,250      
Issued pursuant to notes conversion, value 11,501 $ 8 11,493    
Canceled pursuant to stock compensation plans, shares   (6,313,884)      
Canceled pursuant to stock compensation plans, value 0 $ (6) 6    
Tax withholding for stock compensation plans, shares         742,862
Tax withholding for stock compensation plans, value (168)       $ (168)
Net income (loss) (1,432,578)     (1,432,578)  
Cancellation of Predecessor equity, shares   (509,473,744)     (2,395,633)
Cancellation of Predecessor equity, value (5,331) $ (510) (2,764,915) 2,753,892 $ 6,202
Ending balance, shares at Sep. 18, 2020   49,999,999     0
Ending balance at Sep. 18, 2020 1,095,419 $ 50 1,095,369 0 $ 0
Stock-based compensation, value 8,907   8,907    
Issued pursuant to notes conversion, value 0        
Net income (loss) $ (50,658)     (50,658)  
Ending balance, shares at Dec. 31, 2020 49,999,999 49,999,999     0
Ending balance at Dec. 31, 2020 $ 1,053,668 $ 50 1,104,276 (50,658) $ 0
Stock-based compensation, value 27,205   27,205    
Issued pursuant to notes conversion, value 0        
Tax withholding for stock compensation plans, value $ (2,244)   (2,244)    
Issued pursuant to exercise of warrants, shares 193,657 193,657      
Issued pursuant to exercise of warrants, value $ 759   759    
Net income (loss) $ 56,002     56,002  
Ending balance, shares at Dec. 31, 2021 50,193,656 50,193,656     0
Ending balance at Dec. 31, 2021 $ 1,135,390 $ 50 $ 1,129,996 $ 5,344 $ 0
v3.22.0.1
Nature of Operations and Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2021
Accounting Policies [Abstract]  
Nature of Operations and Summary of Significant Accounting Policies
Note 1. Nature of Operations and Summary of Significant Accounting Policies

Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. The Company is differentiated by our focus on CO2 EOR and the emerging CCUS industry, supported by the Company’s CO2 EOR technical and operational expertise and extensive CO2 pipeline infrastructure.

As further described in Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code below, Denbury Inc. became the successor reporting company of Denbury Resources Inc. (the “Predecessor”) upon the Predecessor’s emergence from bankruptcy on September 18, 2020. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc., and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol DEN.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 28, 2020, Denbury Resources Inc. and its subsidiaries entered into a restructuring support agreement with lenders holding 100% of the revolving loans under our pre-petition revolving bank credit facility and debtholders holding approximately 67.1% of our senior secured second lien notes and approximately 73.1% of our convertible senior notes, which contemplated a restructuring of the Company pursuant to a prepackaged joint plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related to this reorganization.

On the Emergence Date and pursuant to the terms of the Plan and the Confirmation Order, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion in aggregate principal of debt by issuing equity and/or warrants in the Successor to the former holders of that debt, and the Company:

Adopted an amended and restated certificate of incorporation and bylaws which reserved for issuance 250,000,000 shares of common stock, par value $0.001 per share, of Denbury (the “New Common Stock”) and 50,000,000 shares of preferred stock, par value $0.001 per share;
Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor. In accordance with the Plan, claims against and interests in the Predecessor were treated as follows:

Holders of secured pipeline lease claims received payment in full in cash, the collateral securing such pipeline lease claim, reinstatement, or such other treatment rendering such pipeline lease claim unimpaired (see Note 8, Long-Term DebtRestructuring of Pipeline Financing Transactions, for discussion of subsequent pipeline transactions);
Holders of senior secured second lien notes claims received their pro rata share of 47,499,999 shares representing 95% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a management incentive plan;
Holders of convertible senior notes claims received their pro rata share of (a) 2,500,000 shares representing 5% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and
a management incentive plan and (b) 100% of the series A warrants (see below), reflecting up to a maximum of 5% ownership stake in the reorganized company’s equity interests;
Holders of subordinated notes claims received their pro rata share of 54.55% of the series B warrants (see below), reflecting up to a maximum of 3% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
Holders of existing equity interests received their pro rata share of 45.45% of the series B warrants (see below), reflecting up to a maximum of 2.5% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
Issued 2,631,579 series A warrants at an exercise price of $32.59 per share to former holders of the Predecessor’s convertible senior notes and 2,894,740 series B warrants at an exercise price of $35.41 per share to former holders of the Predecessor’s senior subordinated notes and Predecessor’s equity interests; and
Holders of general unsecured claims received payment in full in cash, reimbursement, or such other treatment rendering such general unsecured claim unimpaired.
Entered into a new senior secured revolving credit agreement with a syndicate of banks (the “Successor Bank Credit Agreement”) with total aggregate commitments of $575 million;
Appointed a new board of directors (the “Board”) consisting of four new independent members: Anthony Abate, Caroline Angoorly, Brett Wiggs and James N. “Jim” Chapman, and three continuing members: Dr. Kevin O. Meyers (Chairman of the Board), Lynn A. Peterson and Chris Kendall, Denbury’s President and Chief Executive Officer; and
Adopted a framework for a management incentive plan which reserves for officers, other employees, directors and other service providers a pool of shares of New Common Stock, with initial awards issued on December 4, 2020 (see Note 11, Stock Compensation, for further discussion).

During the Predecessor period, the Company applied Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations, in preparing the consolidated financial statements. FASC Topic 852 requires the financial statements, for periods subsequent to the commencement of the Chapter 11 Restructuring, to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain charges incurred during 2020 related to the Chapter 11 Restructuring, including the write-off of unamortized long-term debt fees and discounts associated with debt classified as liabilities subject to compromise, and professional fees incurred directly as a result of the Chapter 11 Restructuring are recorded as “Reorganization items, net” in our Consolidated Statements of Operations in the Predecessor period. FASC Topic 852 requires certain additional reporting for financial statements prepared between the bankruptcy filing date and the date of emergence from bankruptcy, including:

Reclassification of pre-petition liabilities that are unsecured, under-secured or where it cannot be determined that the liabilities are fully secured, to a separate line item in the Unaudited Condensed Consolidated Balance Sheet titled “Liabilities subject to compromise”; and
Segregation of “Reorganization items, net” as a separate line in the Unaudited Condensed Consolidated Statements of Operations.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with GAAP and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and
natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; (8) estimates made in the calculation of income taxes; (9) estimates made in determining the fair values for purchase price allocations; and (10) fair value estimates including estimates of reorganization value, enterprise value, and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.  While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. 

Business Segment Information

We have evaluated the organization and management of our business and identified only one operating segment related to our oil and natural gas operations. Management measures financial performance and makes capital allocation decisions as a single enterprise and not on a geographical or area-by-area basis. All of our operating revenues, income from operations and assets are generated in the United States.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported total revenues, expenses, net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows:
Successor
In thousandsDecember 31, 2021December 31, 2020
Cash and cash equivalents$3,671 $518 
Restricted cash, current— 1,000 
Restricted cash, long-term46,673 40,730 
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows$50,344 $42,248 

Restricted cash, long-term in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Consolidated Balance Sheets.

Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic.  Proceeds
received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant.

Depletion.  The costs capitalized, including production equipment and future development costs, are depleted using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million during the year ended December 31, 2019, whereby these costs were transferred to the full cost amortization base. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 coronavirus pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting, for additional information).

Write-Down of Oil and Natural Gas Properties.  The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional CO2 capital costs to develop the proved oil and natural gas reserves.  Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $63.86 at December 31, 2021, $35.84 at December 31, 2020, $40.08 at September 18, 2020, and $55.55 at December 31, 2019. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. Primarily as a result of the commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. We did not record any ceiling test write-downs during the 2019 Predecessor period.

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
 
Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs until we are able to recognize proved reserves associated with the development project.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and any previously deferred unevaluated development costs become subject to depletion.

CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 operating and discovery expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO2 (see Tertiary Injection Costs above for further discussion).

Costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets.  Capitalized CO2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.

Pipelines

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years. Capitalized costs include $22.4 million of CO2 pipelines as of December 31, 2021, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2021.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life.  Vehicles are generally depreciated over a useful life of one to five years, furniture and fixtures over a life of one to ten years, and computer equipment and software are generally depreciated over a useful life of one to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.

Intangible Assets

Our intangible assets subject to amortization represent amounts assigned in fresh start accounting to long-term contracts to sell CO2 to industrial customers. We amortize the CO2 contract intangible assets on a straight-line basis over their estimated useful lives, which range from seven to 14 years. Total amortization expense for our intangible assets was $9.1 million during the year ended December 31, 2021, $2.7 million during the Successor period September 19, 2020 through December 31, 2020,
$1.7 million for the Predecessor period January 1, 2020 through September 18, 2020, and $2.4 million during the year ended 2019. The following table summarizes the carrying value of our intangible assets as of December 31, 2021 and 2020:
Successor
In thousandsDecember 31, 2021December 31, 2020
Long-term contracts to sell CO2 to industrial customers
$97,943 $97,943 
Other intangibles2,179 2,167 
Accumulated amortization(11,874)(2,748)
Net book value$88,248 $97,362 

As of December 31, 2021, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
In thousands 
2022$9,120 
20239,117 
20249,117 
20259,117 
20269,117 
 
Impairment Assessment of Long-Lived Assets

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO2 properties and pipelines, and for the Successor period also included long-term contracts to sell CO2 to industrial customers.

We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2021, 2020 or 2019.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool.

Asset retirement obligations are estimated at the present value of expected future net cash flows.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.
Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  Our derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change.

Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders).  There are no margin requirements with the counterparties of our derivative contracts.

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We would not expect the loss of any purchaser to have a material adverse effect upon our operations.  For the year ended December 31, 2021 (Successor), four purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (28%), Hunt Crude Oil Supply Company (12%), Marathon Petroleum (11%) and Sunoco Inc. (11%). For the Successor period September 19, 2020 through December 31, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Marathon Petroleum (13%) and Hunt Crude Oil Supply Company (12%), and for the Predecessor period January 1, 2020 through September 18, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Hunt Crude Oil Supply Company (12%) and Marathon Petroleum (12%). For the year ended December 31, 2019 (Predecessor), three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. (11%).

Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units, nonvested performance stock units, and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and convertible senior notes.

The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Numerator
Net income (loss) – basic$56,002 $(50,658)$(1,432,578)$216,959 
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax— — — 14,134 
Net income (loss) – diluted$56,002 $(50,658)$(1,432,578)$231,093 
Denominator
Weighted average common shares outstanding – basic50,918 50,000 495,560 459,524 
Effect of potentially dilutive securities  
Restricted stock units762 — — — 
Warrants2,138 — — — 
Restricted stock and performance-based equity awards— — — 2,396 
Convertible senior notes(1)
— — — 48,421 
Weighted average common shares outstanding – diluted53,818 50,000 495,560 510,341 

(1)For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Predecessor’s common stock issuable upon full conversion of the convertible senior notes which were issued on June 19, 2019 (see Note 8, Long-Term Debt – 2019 Predecessor Debt Reduction Transactions).

For each of the periods from September 19, 2020 through December 31, 2020 (Successor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 50.0 million for the period September 19, 2020 through December 31, 2020 and 584.4 million for the period January 1, 2020 through September 18, 2020, if the Company had recognized net income during those periods.

Basic weighted average common shares during the year ended December 31, 2021 includes 1,383,144 performance-based and restricted stock units which are fully vested as of December 31, 2021. Although vesting criteria for these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023. During the Predecessor periods, basic weighted average common shares includes restricted stock that vested during the periods.

For purposes of calculating diluted weighted average common shares for the years ended December 31, 2021 and 2019, the nonvested restricted stock units, nonvested restricted stock and performance-based equity awards, along with unexercised
warrants are included in the computation using the treasury stock method, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods.

The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the year ended December 31, 2021, the period September 19, 2020 through December 31, 2020, and the year ended December 31, 2019, as their effect would have been antidilutive, as of the respective dates:
SuccessorPredecessor
In thousandsDecember 31, 2021December 31, 2020December 31, 2019
Restricted stock units— 1,220 — 
Warrants— 5,526 — 
Stock appreciation rights— — 1,981 
Restricted stock and performance-based equity awards— — 4,445 
    
For the period September 19, 2020 through December 31, 2020, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the periods. At December 31, 2021, the Company had approximately 5.2 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.6 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of December 31, 2021, 11,694 series A warrants and 327,266 series B warrants have been exercised in exchange for a total of 193,657 shares. The warrants may be exercised for cash or on a cashless basis.

Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.  Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.

Recent Accounting Pronouncements

Recently Adopted

Income Taxes. In December 2019, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
v3.22.0.1
Fresh Start Accounting
12 Months Ended
Dec. 31, 2021
Fresh Start Accounting
Note 2. Fresh Start Accounting

Fresh Start Accounting

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with FASC Topic 852, Reorganizations, which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. The criteria requiring fresh start accounting are: (1) the holders of the then-existing common shares of the Predecessor received less than 50 percent of the new common shares of the Successor outstanding upon emergence from bankruptcy and (2) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.
Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020, and therefore certain values and operational results of the consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.

Reorganization Value

The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. Under FASC Topic 852, reorganization value generally approximates the fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of the restructuring. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Company’s financial advisors in setting an estimated range of enterprise values. As set forth in the Plan and Disclosure Statement approved by the Bankruptcy Court, the valuation analysis resulted in an enterprise value between $1.1 billion and $1.5 billion, with a midpoint of $1.3 billion. For U.S. GAAP purposes, we valued the Successor’s individual assets, liabilities, and equity instruments and determined the value of the enterprise was approximately $1.3 billion as of the Emergence Date, which fell in line with the midpoint of the forecast enterprise value ranges approved by the Bankruptcy Court. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process.

The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Less: Total debt(231,022)
Equity value$1,095,419 

The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted entity) and total reorganization value:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Plus: Current liabilities excluding current maturities of long-term debt239,738 
Plus: Non-interest-bearing noncurrent liabilities185,228 
Reorganization value of the reconstituted Successor$1,751,407 

With the assistance of third-party valuation advisors, we determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach.

The enterprise value and corresponding equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of September 18, 2020. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.
Reorganization Items, Net

“Reorganization items, net” in our Consolidated Statements of Operations includes (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments. Professional service provider charges associated with our restructuring that were incurred outside of this period (before the Petition Date and after the Emergence Date) are recorded in “Other expenses” in our Consolidated Statements of Operations. Contractual interest expense of $22.0 million from the Petition Date through the Emergence Date associated with our outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes was not accrued or recorded in the consolidated statement of operations as interest expense.

The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
Debtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 

Valuation Process

The fair values of our principal assets, including oil and natural gas properties, CO2 properties, pipelines, other property and equipment, long-term contracts to sell CO2 to industrial customers, favorable and unfavorable vendor contracts, pipeline financing liabilities and right-of-use assets, asset retirement obligations and warrants were estimated as of the Emergence Date.

Oil and Natural Gas Properties

The Company’s principal assets are its oil and natural gas properties, which are accounted for under the full cost accounting method as described in Note 1, Nature of Operations and Summary of Significant Accounting PoliciesOil and Natural Gas Properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date.

The fair value analysis was based on the Company’s estimated future production rates of proved and probable reserves as prepared by the Company’s independent petroleum engineers. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenues were based upon future production rates and forward strip oil and natural gas prices as of the Emergence Date through 2024 and escalated for inflation thereafter, adjusted for differentials. Operating costs were adjusted for inflation beginning in year 2025. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. The discounted cash flow models also included adjustments for income tax expenses.

Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets. Reserve values were also adjusted for any asset retirement obligations as well as for CO2 indirect costs not directly allocable to oil fields. Based on this analysis, the
Company concluded the fair value of its proved and probable reserves was $865.4 million as of the Emergence Date (see footnote 10 to Fresh Start Adjustments discussion below).

CO2 Properties

The fair value of CO2 properties includes the value of CO2 mineral rights and associated infrastructure and was determined using the discounted cash flow method under the income approach. After-tax cash flows were forecast based on expected costs to produce and transport CO2 as estimated by management, and income was imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily develop or produce natural gas. Cash flows were also adjusted for a market participant profit on CO2 costs, since Denbury charges oil fields for CO2 use on a cost basis. Cash flows were then discounted using a rate considering reduced risk associated with CO2 industrial sales.

Pipelines

The fair values of our pipelines were determined using a combination of the replacement cost method under the cost approach and the discounted cash flow method under the income approach. The replacement cost method considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. For assets valued using the discounted cash flow method, after-tax cash flows were forecast based on expected costs estimated by management, and profits were imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily transport natural gas. Pipeline depreciable lives represent the remaining estimated useful lives of the pipelines.

Other Property and Equipment

The fair value of the non-reserve related property and equipment such as land, buildings, equipment, leasehold improvements and software was determined using the replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow.

Long-Term Contracts to Sell CO2 to Industrial Customers

The fair value of long-term contracts to sell CO2 to industrial customers was determined using the multi-period excess earnings method (“MPEEM”) under the income approach. MPEEM attributes cash flow to a specific intangible asset based on residual cash flows from a set of assets generating revenues after accounting for appropriate returns on and of other assets contributing to that revenue generation. Cash flows were forecast based on expected changes in pricing, volumes, renewal rates, and costs using volumes and prices through and beyond the initial contract terms. After-tax cash flows were discounted using a rate considering reduced risk of these industrial contracts relative to overall oil and gas production risks.

Favorable and Unfavorable Vendor Contracts

We recognized both favorable and unfavorable contracts using the incremental value method under the income approach. The incremental value method calculates value on the basis of the pricing differential between historical contracted rates and estimated pricing that the Company would most likely receive if it entered into similar contract conditions (other than the price) as of the Emergence Date. The differential is applied to expected contract volumes, tax-affected and discounted at a discount rate consistent with the risk of the associated cash flows.

Asset Retirement Obligations

The fair value of the asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free rate (“CARFR”). The new CARFR was based on an evaluation of similar industry peers with similar factors such as emergence, new capital structure and current rates for oil and gas companies.
Pipeline Financing Liabilities

The fair value of the pipeline financing liabilities was measured as the present value of the remaining payments under the restructured pipeline agreements (see Note 8, Long-Term DebtRestructuring of Pipeline Financing Transactions, for further discussion).

Warrants

The fair values of the warrants issued upon the Emergence Date were estimated by applying a Black-Scholes model. The Black-Scholes model is a pricing model used to estimate the fair value of a European-style call or put option/warrant based on a current stock price, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield.

The model used the following assumptions: implied stock price (total equity divided by total shares outstanding) of the Successor’s shares of common stock of $22.14; exercise price per share of $32.59 and $35.41 for series A and B warrants, respectively; expected volatility of 49.3% and 53.6% for series A and B warrants, respectively; risk-free interest rates of 0.3% and 0.2% for series A and B warrants, respectively, using the United States Treasury Constant Maturity rates; and an expected annual dividend yield of 0%. Expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available. The time to maturity of the warrants was based on the contractual terms of the warrants of five and three years for series A and series B warrants, respectively. The values were also adjusted for potential dilution impacts.

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants.
As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Assets
Current assets 
Cash and cash equivalents$73,372 $(27,787)
(1)
$— $45,585 
Restricted cash— 10,662 
(2)
— 10,662 
Accrued production receivable112,832 — — 112,832 
Trade and other receivables, net36,221 — — 36,221 
Derivative assets32,635 — — 32,635 
Other current assets12,968 (539)
(3)
— 12,429 
Total current assets268,028 (17,664)— 250,364 
Property and equipment 
Oil and natural gas properties (using full cost accounting)
Proved properties11,723,546 — (10,941,313)782,233 
Unevaluated properties650,553 — (538,570)111,983 
CO2 properties
1,198,515 — (1,011,169)187,346 
Pipelines2,339,864 — (2,207,246)132,618 
Other property and equipment201,565 — (104,152)97,413 
Less accumulated depletion, depreciation, amortization and impairment(12,864,141)— 12,864,141 — 
Net property and equipment3,249,902 — (1,938,309)
(10)
1,311,593 
Operating lease right-of-use assets1,774 — 69 
(10)
1,843 
Derivative assets501 — — 501 
Intangible assets, net20,405 — 79,678 
(11)
100,083 
Other assets81,809 8,241 
(4)
(3,027)
(12)
87,023 
Total assets$3,622,419 $(9,423)$(1,861,589)$1,751,407 
As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Liabilities and Stockholders’ Equity
Current liabilities 
Accounts payable and accrued liabilities$67,789 $102,793 
(5)
$3,738 
(13)
$174,320 
Oil and gas production payable39,372 16,705 
(6)
— 56,077 
Derivative liabilities8,613 — — 8,613 
Current maturities of long-term debt— 73,199 
(6)
364 
(14)
73,563 
Operating lease liabilities— 757 
(6)
(29)
(10)
728 
Total current liabilities115,774 193,454 4,073 313,301 
Long-term liabilities 
Long-term debt, net of current portion140,000 42,610 
(6)
(25,151)
(14)
157,459 
Asset retirement obligations2,727 180,408 
(6)
(24,697)
(10)
158,438 
Derivative liabilities295 — — 295 
Deferred tax liabilities, net— 417,951 
(6)(15)
(414,120)
(15)
3,831 
Operating lease liabilities— 515 
(6)
10 
(10)
525 
Other liabilities— 3,540 
(6)
18,599 
(16)
22,139 
Total long-term liabilities not subject to compromise143,022 645,024 (445,359)342,687 
Liabilities subject to compromise2,823,506 (2,823,506)
(6)
— — 
Commitments and contingencies (Note 14)
Stockholders’ equity
Predecessor preferred stock— — — — 
Predecessor common stock510 (510)
(7)
— — 
Predecessor paid-in capital in excess of par2,764,915 (2,764,915)
(7)
— — 
Predecessor treasury stock, at cost(6,202)6,202 
(7)
— — 
Successor preferred stock— — — — 
Successor common stock— 50 
(8)
— 50 
Successor paid-in capital in excess of par— 1,095,369 
(8)
— 1,095,369 
Accumulated deficit(2,219,106)3,639,409 
(9)
(1,420,303)
(17)
— 
Total stockholders equity
540,117 1,975,605 (1,420,303)1,095,419 
Total liabilities and stockholders’ equity$3,622,419 $(9,423)$(1,861,589)$1,751,407 

Reorganization Adjustments

(1)Represents the net cash payments that occurred on the Emergence Date as follows:
In thousands
Sources:
Cash proceeds from Successor Bank Credit Agreement$140,000 
Total cash proceeds140,000 
Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility(140,000)
Retained professional service provider fees paid to escrow account(10,662)
Non-retained professional service provider fees paid(7,420)
Accrued interest and fees on DIP Facility(1,464)
Debt issuance costs related to Successor Bank Credit Agreement(8,241)
Total cash uses(167,787)
Net uses$(27,787)
(2)Represents the transfer of funds to a restricted cash account utilized for the payment of fees to retained professional service providers assisting in the bankruptcy process.

(3)Represents the write-off of costs related to the DIP Facility and a run-off policy for directors’ and officers’ insurance coverage, partially offset by the recording of prepaid amounts for non-retained professional service provider fees.

(4)Represents debt issuance costs related to the Successor Bank Credit Agreement.

(5)Adjustments to accounts payable and accrued liabilities as follows:
In thousands
Accrual of professional service provider fees$2,826 
Payment of accrued interest and fees on DIP Facility(1,464)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise101,431 
Accounts payable and accrued liabilities$102,793 

(6)Liabilities subject to compromise were settled as follows in accordance with the Plan:
In thousands
Liabilities subject to compromise prior to the Emergence Date:
Settled liabilities subject to compromise
Senior secured second lien notes$1,629,457 
Convertible senior notes234,015 
Senior subordinated notes251,480 
Total settled liabilities subject to compromise2,114,952 
Reinstated liabilities subject to compromise
Current maturities of long-term debt73,199 
Accounts payable and accrued liabilities101,431 
Oil and gas production payable16,705 
Operating lease liabilities, current757 
Long-term debt, net of current portion42,610 
Asset retirement obligations180,408 
Deferred tax liabilities289,389 
Operating lease liabilities, long-term515 
Other long-term liabilities3,540 
Total reinstated liabilities subject to compromise708,554 
Total liabilities subject to compromise2,823,506 
Issuance of New Common Stock to second lien note holders(1,014,608)
Issuance of New Common Stock to convertible note holders(53,400)
Issuance of series A warrants to convertible note holders(15,683)
Issuance of series B warrants to senior subordinated note holders (6,398)
Reinstatement of liabilities subject to compromise(708,553)
Gain on settlement of liabilities subject to compromise$1,024,864 

(7)Represents the cancellation of the Predecessor’s common stock, treasury stock, and related components of the Predecessor’s paid-in capital in excess of par. Paid-in capital in excess of par includes $4.6 million as a result of terminated Predecessor stock compensation plans.
(8)Represents the Successor’s common stock and additional paid-in capital as follows:
In thousands
Capital in excess of par value of 47,499,999 issued and outstanding shares of New Common Stock issued to holders of the senior secured second lien note claims$1,014,608 
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock issued to holders of the convertible senior note claims53,400 
Fair value of series A warrants issued to convertible senior note holders15,683 
Fair value of series B warrants issued to senior subordinated note holders6,398 
Fair value of series B warrants issued to Predecessor equity holders5,330 
Total change in Successor common stock and additional paid-in capital1,095,419 
Less: Par value of Successor common stock(50)
Change in Successor additional paid-in capital$1,095,369 

(9)Reflects the cumulative net impact of the effects on accumulated deficit as follows:
In thousands
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock$2,763,824 
Gain on settlement of liabilities subject to compromise1,024,864 
Acceleration of Predecessor stock compensation expense(4,601)
Recognition of tax expenses related to reorganization adjustments(128,556)
Professional service provider fees recognized at emergence(9,700)
Issuance of series B warrants to Predecessor equity holders(5,330)
Other(1,092)
Net impact to Predecessor accumulated deficit$3,639,409 

Fresh Start Adjustments

(10)Reflects fair value adjustments to our (i) oil and natural gas properties, CO2 properties, pipelines, and other property and equipment, as well as the elimination of accumulated depletion, depreciation, and amortization, (ii) operating lease right-of-use assets and liabilities, and (iii) asset retirement obligations.

(11)Reflects fair value adjustments to our long-term contracts to sell CO2 to industrial customers.

(12)Reflects fair value adjustments to our other assets as follows:
In thousands
Fair value adjustment for CO2 and oil pipeline line-fill
$(3,698)
Fair value adjustments for escrow accounts671 
Fair value adjustments to other assets$(3,027)

(13)Reflects fair value adjustments to accounts payable and accrued liabilities as follows:
In thousands
Fair value adjustment for the current portion of an unfavorable vendor contract$3,500 
Fair value adjustment for the current portion of Predecessor asset retirement obligation689 
Write-off accrued interest on NEJD pipeline financing(451)
Fair value adjustments to accounts payable and accrued liabilities$3,738 
(14)Represents adjustments to current and long-term maturities of debt associated with pipeline lease financings. The cumulative effect is as follows:
In thousands
Fair value adjustment for Free State pipeline lease financing$(24,699)
Fair value adjustment for NEJD pipeline lease financing(88)
Fair value adjustments to current and long-term maturities of debt$(24,787)

Our pipeline lease financings were restructured in late October 2020 (see Note 8, Long-Term DebtRestructuring of Pipeline Financing Transactions).

(15)Represents (i) adjustment to deferred taxes, including the recognition of tax expenses related to reorganization adjustments as a result of the cancellation of debt and retaining tax attributes for the Successor and the reinstatement of deferred tax liabilities subject to compromise totaling $128.6 million and (ii) adjustments to deferred tax liabilities related to fresh start accounting of $414.1 million.

(16)Represents a fair value adjustment for the long-term portion of an unfavorable vendor contract.

(17)Represents the cumulative effect of the fresh start accounting adjustments discussed above.
v3.22.0.1
Acquisition and Divestitures
12 Months Ended
Dec. 31, 2021
Business Combinations [Abstract]  
Acquisition and Divestitures
Note 3. Acquisition and Divestitures

Acquisition of Wyoming CO2 EOR Fields

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million cash (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and if the price condition is met, the second $4 million payment will be due in January 2023. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of December 31, 2021, the fair value of the contingent consideration recorded on our Consolidated Balance Sheets was $7.7 million. The $2.4 million increase at December 31, 2021 from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Consolidated Statements of Operations.

The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and
liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:

In thousands
Consideration:
Cash consideration$10,906 
Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties60,101 
Other property and equipment1,685 
Asset retirement obligations(39,794)
Contingent consideration(5,320)
Other liabilities(5,766)
Fair value of net assets acquired$10,906 

Divestitures

Hartzog Draw Deep Mineral Rights

On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.

Houston Area Land Sales

During the second half of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We received cash proceeds of $15.2 million from the sales and recognized a $10.3 million gain to “Other income” in our Consolidated Statements of Operations.

Gulf Coast Working Interests Sale

On March 4, 2020, the Predecessor sold half of its working interest positions in four southeast Texas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. The Predecessor did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.
v3.22.0.1
Revenue Recognition
12 Months Ended
Dec. 31, 2021
Revenue from Contract with Customer [Abstract]  
Revenue Recognition
Note 4. Revenue Recognition

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition:

Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the
contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains control (the identified performance obligation is satisfied).

Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary.

Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets.

In addition to revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts, in certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following table summarizes our revenues by product type:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Oil sales $1,148,022 $199,769 $489,251 $1,205,083 
Natural gas sales11,933 1,339 2,850 6,937 
CO2 sales and transportation fees
44,175 9,419 21,049 34,142 
Oil marketing revenues38,742 5,376 8,543 14,198 
Total revenues$1,242,872 $215,903 $521,693 $1,260,360 
v3.22.0.1
Leases
12 Months Ended
Dec. 31, 2021
Leases [Abstract]  
Leases
Note 5. Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 14 years, with certain land leases having
remaining terms up to 48 years.  Leases with a term of 12 months or less are not recorded on our balance sheet. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our office leases:
Successor
In thousandsDecember 31, 2021December 31, 2020
Operating leases
Operating lease right-of-use assets$19,502 $20,342 
Operating lease liabilities – current$4,677 $1,350 
Operating lease liabilities – long-term17,094 19,460 
Total operating lease liabilities$21,771 $20,810 

The majority of our leases contain renewal options, typically exercisable at our sole discretion. At emergence, we recorded right-of-use assets and liabilities based on the fair value of lease payments and utilized our incremental borrowing rate based on information available at the Emergence Date. The following weighted average remaining lease terms and discount rates related to our outstanding operating leases:
Successor
December 31, 2021December 31, 2020
Weighted average remaining lease term5.2 years6.3 years
Weighted average discount rate5.4 %5.6 %

We account for lease and nonlease components in a contract as a single lease component for all asset classes. Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. Variable lease costs represent additional payments in excess of our minimum base rental payments under our office space leases. The Predecessor Company previously subleased part of the office space included in its operating leases for which it received rental payments. Since those office space leases were terminated during the Chapter 11 Restructuring, the underlying sublease agreements were also terminated. The Successor
Company subsequently entered into an operating lease for a new corporate office space which commenced in October 2020. The following table summarizes the components of lease costs and sublease income:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousandsIncome Statement
Operating lease costGeneral and administrative expenses$4,102 $872 $5,683 $8,924 
Lease operating expenses655 158 214 58 
CO2 operating and discovery expenses
50 14 37 
$4,807 $1,044 $5,934 $8,987 
Finance lease cost
Amortization of right-of-use assetsDepletion, depreciation, and amortization$— $$$1,188 
Interest on lease liabilitiesInterest expense— 40 
Total finance lease cost$— $$12 $1,228 
Variable lease cost$670 $258 $3,688 $4,852 
Sublease incomeGeneral and administrative expenses$— $100 $2,584 $4,127 

Our statement of cash flows included the following activity related to our operating and finance leases:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases$2,830 $341 $7,341 $10,995 
Operating cash flows from interest on finance leases— 40 
Financing cash flows from finance leases— 78 10 1,275 
Right-of-use assets obtained in exchange for lease obligations
Operating leases2,683 19,902 1,049 415 
Finance leases— — 162 — 
The following table summarizes by year the maturities of our lease liabilities as of December 31, 2021:
Operating
In thousandsLeases
2022$5,705 
20234,712 
20244,138 
20254,177 
20264,203 
Thereafter2,326 
Total minimum lease payments25,261 
Less: Amount representing interest(3,490)
Present value of minimum lease liabilities$21,771 
v3.22.0.1
Asset Retirement Obligations
12 Months Ended
Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Note 6. Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Beginning asset retirement obligations$186,281 $163,368 $181,760 
Liabilities incurred and assumed during period43,701 738 736 
Revisions in estimated retirement obligations69,059 22,660 3,592 
Liabilities settled and sold during period(10,783)(3,439)(10,041)
Accretion expense14,353 2,954 11,329 
Fresh start accounting adjustment— — (24,008)
Ending asset retirement obligations302,611 186,281 163,368 
Less: current asset retirement obligations(1)
(18,373)(6,943)(4,930)
Long-term asset retirement obligations$284,238 $179,338 $158,438 

(1)Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Liabilities assumed relate to our March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures), with liabilities incurred generally relating to wells and facilities. Revisions during 2021 primarily related to increased well abandonment cost estimates at certain of these fields and an acceleration in the estimated timing of certain future abandonment activities.

We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these escrow accounts were $55.6 million and $55.2 million as of December 31, 2021 and 2020, respectively.  These balances are primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are included in “Other assets” in our Consolidated Balance Sheets.  A portion of these investments are included in cash, cash equivalents, and restricted cash balances on our Consolidated Statements of Cash Flows (see Note 1, Nature of Operations and Summary of Significant Accounting Policies – Cash, Cash Equivalents, and Restricted Cash). The carrying values of these investments approximate their estimated fair market value as of December 31, 2021 and 2020.
v3.22.0.1
Unevaluated Property
12 Months Ended
Dec. 31, 2021
Property, Plant and Equipment [Abstract]  
Unevaluated Property
Note 7. Unevaluated Property

A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2021, and the year in which the costs were incurred follows:
 December 31, 2021
 Costs Incurred During: 
In thousands2021Successor 2020
Fresh Start Adjustments (Sept. 18, 2020)(1)
Total
Property acquisition costs$— $— $68,103 $68,103 
Exploration and development39,481 46 — 39,527 
Capitalized interest3,576 963 — 4,539 
Total$43,057 $1,009 $68,103 $112,169 

(1)Reflects the carrying values of our unevaluated properties as a result of the application of fresh start accounting upon emergence from bankruptcy (see Note 2, Fresh Start Accounting, for additional information) that remain in unevaluated properties as of December 31, 2021.

Our property acquisition costs reflected in the table above relate to fair values assigned during fresh start accounting and are primarily associated with our Cedar Creek Anticline fields and CO2 tertiary potential at Tinsley and Salt Creek fields. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil field projects at Cedar Creek Anticline that are under development but did not have associated proved reserves at December 31, 2021.

Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined.  We review the excluded properties for impairment at least annually.  We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten years.  Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.
v3.22.0.1
Long-Term Debt
12 Months Ended
Dec. 31, 2021
Debt Disclosure [Abstract]  
Long-Term Debt
Note 8. Long-Term Debt

The table below reflects long-term debt outstanding as of December 31, 2021 and 2020:
 Successor
In thousandsDecember 31, 2021December 31, 2020
Senior Secured Bank Credit Agreement$35,000 $70,000 
Pipeline financings— 68,008 
Total debt principal balance35,000 138,008 
Less: current maturities of long-term debt— (68,008)
Long-term debt$35,000 $70,000 

The ultimate parent company in our corporate structure, Denbury Inc., is the sole issuer of all our outstanding obligations under our Successor Bank Credit Agreement. Denbury Inc. has no independent assets or operations.  Each of the subsidiary guarantors of such obligations is 100% owned, directly or indirectly, by Denbury Inc, and the guarantees of such obligations are full and unconditional and joint and several.

Prior to our emergence from bankruptcy, our debt consisted of the Predecessor’s Bank Credit Agreement, senior secured second lien notes, convertible senior notes, senior subordinated notes, pipeline financings, and capital lease obligations. On the Emergence Date, pursuant to the terms of the Plan, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor to the holders of that debt. See Note 1, Nature of Operations and Summary of Significant Accounting PoliciesEmergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, for additional information.
Senior Secured Bank Credit Facility

In connection with our emergence from Chapter 11 proceedings on September 18, 2020, we entered into a new credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto. The Successor Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base and lender commitments of $575 million. Additionally, under the Successor Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Successor Bank Credit Agreement. Availability under the Successor Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. If our outstanding debt under the Successor Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Successor Bank Credit Agreement matures on January 30, 2024.

The Successor Bank Credit Agreement limits our ability to pay dividends on our common stock or make other restricted payments in an amount not to exceed Distributable Free Cash Flow (as defined in the Successor Bank Credit Agreement), but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Successor Bank Credit Agreement is at least 20%. The Successor Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.

The Successor Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and commodity accounts of Denbury Inc. and such subsidiaries (as applicable); and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

The Successor Bank Credit Agreement contains certain financial performance covenants including the following:

A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and
A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.

For purposes of computing the current ratio per the Successor Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Successor Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding.

Loans under the Successor Bank Credit Agreement are subject to varying rates of interest based on either (1) for alternate base rate loans, a base rate determined under the Successor Bank Credit Agreement plus an applicable margin ranging from 2% to 3% per annum, or (b) for LIBOR Loans, the LIBOR rate (subject to a 1% floor) plus an applicable margin ranging from 3% to 4% per annum (capitalized terms as defined in the Successor Bank Credit Agreement). The weighted average interest rate on borrowings outstanding as of December 31, 2021 under the Successor Bank Credit Agreement was 4.0%. The undrawn portion of the aggregate lender commitments under the Successor Bank Credit Agreement is subject to a commitment fee of 0.5%. As of December 31, 2021, we were in compliance with all debt covenants under the Successor Bank Credit Agreement.

The above description of our Successor Bank Credit Agreement and defined terms are contained in the Successor Bank Credit Agreement.
Restructuring of Pipeline Financing Transactions

In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The NEJD pipeline system included a 20-year secured financing lease, and the Free State Pipeline included a long-term transportation service agreement. In late October 2020, we restructured our CO2 pipeline financing arrangements with Genesis, whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million which was paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020.

Predecessor Senior Secured Bank Credit Facility

From December 2014 through September 18, 2020, the Company maintained a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Predecessor Bank Credit Agreement”). All but a minor portion of the Predecessor Bank Credit Agreement was refinanced through the DIP Facility from August 4, 2020 through September 18, 2020, which was in turn refinanced by the Successor Bank Credit Agreement upon emergence from the Chapter 11 Restructuring.

Extinguishment of Predecessor Senior Secured Second Lien Notes, Convertible Senior Notes, and Senior Subordinated Notes

Upon emergence from the Chapter 11 Restructuring on September 18, 2020, the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”), 9¼% Senior Secured Second Lien Notes due 2022, 7¾% Senior Secured Second Lien Notes due 2024, 7½% Senior Secured Second Lien Notes due 2024, 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Notes”), 6⅜% Senior Subordinated Notes due 2021, 5½% Senior Subordinated Notes due 2022, and 4⅝% Senior Subordinated Notes due 2023 were fully extinguished by issuing equity and/or warrants in the Successor to the holders of that debt. The Predecessor debt discussions that follow are included to provide context on the impact of these transactions on the Predecessor’s financial statements.

Second Quarter 2020 Conversion of 2024 Convertible Notes

During the second quarter of 2020, holders of $19.9 million aggregate principal amount outstanding of the Predecessor’s 2024 Convertible Notes converted their notes into shares of the Predecessor’s common stock, at the rates specified in the indenture for the notes, resulting in the issuance of 7.4 million shares of Predecessor common stock upon conversion. The debt principal balance, net of debt discounts, totaling $13.9 million, was reclassified to “Paid-in capital in excess of par” and “Common stock” in the Consolidated Balance Sheet of the Predecessor upon the conversion of the notes into shares of Predecessor common stock.

First Quarter 2020 Repurchases of Senior Secured Notes

During March 2020, the Predecessor repurchased a total of $30.2 million aggregate principal amount of its 2021 Notes in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, the Predecessor recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

2019 Predecessor Debt Reduction Transactions

With a focus on reducing the amount of outstanding debt principal, the Predecessor engaged in a series of debt exchanges and repurchase transactions, resulting in total gains on extinguishments of $156.0 million for the year ended December 31, 2019, in its Consolidated Statements of Operations.

Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the straight line or effective interest method over the term of each related facility or
borrowing.  Remaining unamortized debt issuance costs were $5.7 million and $8.4 million at December 31, 2021 and 2020, respectively.  Issuance costs associated with our Successor Bank Credit Agreement are included in “Other assets” in the Consolidated Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2021, our indebtedness is payable over the next five years and thereafter as follows:
In thousands 
2022$— 
2023— 
202435,000 
2025— 
2026— 
Thereafter— 
Total indebtedness$35,000 
v3.22.0.1
Income Taxes
12 Months Ended
Dec. 31, 2021
Income Tax Disclosure [Abstract]  
Income Taxes
Note 9. Income Taxes

Our income tax provision (benefit) is as follows:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Current income tax expense (benefit)   
Federal$— $— $(6,407)$2,645 
State403 30 (853)1,236 
Total current income tax expense (benefit)403 30 (7,260)3,881 
Deferred income tax expense (benefit)   
Federal— — (319,011)89,950 
State364 (2,556)(89,858)10,521 
Total deferred income tax expense (benefit)364 (2,556)(408,869)100,471 
Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 

At December 31, 2021, we had federal net operating loss carryforwards (“NOLs”) and business credit carryforwards (before provision for valuation allowance) totaling $10.3 million and $18.1 million, respectively. Our federal NOLs may be carried forward indefinitely and our credit carryforwards begin to expire in 2041. NOL, enhanced oil recovery credit and research and development credit carryforwards generated prior to January 1, 2021 were fully reduced in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 pertaining to discharge of indebtedness. At December 31, 2021, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act passed in 2017 will be fully refundable by 2022, and are recorded as a receivable on the balance sheet, and state NOLs and tax credits totaling $54.9 million (before provision for valuation allowance) related to all our state operations, which continue as carryforwards for the Successor. Our state NOLs expire in various years, starting in 2025.

Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2021 and 2020 balance sheet dates.  As of December 31, 2021, we had $74.1 million of net state deferred tax assets associated with operations in Louisiana, Mississippi, Montana, North Dakota and Alabama, which were
fully offset with valuation allowances. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. The changes in our valuation allowance are detailed below:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Beginning balance$129,408 $129,840 $77,215 $51,093 
Charges29,345 2,269 77,138 26,122 
Deductions(33,291)(2,701)(24,513)— 
Ending balance$125,462 $129,408 $129,840 $77,215 

As of December 31, 2021, we had no unrecognized tax benefits recorded related to an uncertain tax position.

Significant components of our deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
 Successor
In thousandsDecember 31, 2021December 31, 2020
Deferred tax assets  
Loss and tax credit carryforwards – state$54,943 $55,979 
Derivative contracts30,892 13,090 
Accrued liabilities and other reserves19,567 15,632 
Business credit carryforwards18,066 — 
Loss carryforwards – federal10,310 — 
Lease liabilities4,523 6,354 
Property and equipment2,613 59,207 
Other4,206 4,092 
Valuation allowances(125,462)(129,408)
Total deferred tax assets19,658 24,946 
Deferred tax liabilities  
CO2 and other contracts
(17,208)(20,030)
Operating lease right-of-use assets(4,088)(6,190)
Total deferred tax liabilities(21,296)(26,220)
Total net deferred tax liability$(1,638)$(1,274)
Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Income tax provision calculated using the federal statutory income tax rate$11,921 $(11,169)$(388,228)$67,475 
State income taxes, net of federal income tax benefit450 (2,532)(86,937)7,435 
Tax shortfall (windfall) on stock-based compensation deduction(267)— (1,502)1,912 
Nondeductible compensation5,057 — — — 
Change in valuation allowance(2,928)9,653 19,344 26,122 
Enhanced oil recovery credits generated(14,272)— — — 
Tax attributes reduction – net of CODI exclusion— — 31,667 — 
Other806 1,522 9,527 1,408 
Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 
 
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The statutes of limitation for our income tax returns for tax years ending prior to 2018 have lapsed and therefore are not subject to examination by respective taxing authorities. We have not paid any significant interest or penalties associated with our income taxes.
v3.22.0.1
Stockholders' Equity
12 Months Ended
Dec. 31, 2021
Stockholders' Equity Note [Abstract]  
Stockholders' Equity
Note 10. Stockholders’ Equity

Registration Rights Agreement

On September 18, 2020, in connection with the Company’s emergence from Chapter 11 proceedings, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain former beneficial holders of second lien notes of the Predecessor that entered into the restructuring support agreement leading to the restructuring of the Company pursuant to a prepackaged plan of reorganization and pursuant to which the Company included these holders’ shares of common stock of the Successor in an automatically effective resale registration statement filed with the SEC in April 2021 for their use in connection with resale of these shares. Under the Registration Rights Agreement, these security holders have customary demand and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an offering and the Company’s right to delay or withdraw a registration statement under certain circumstances.

401(k) Plan

We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations.  We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately.  Matching contributions to the 401(k) plan totaled $5.1 million during 2021 (Successor), $1.1 million for the period September 19, 2020 through December 31, 2020 (Successor), $4.4 million for the period January 1, 2020 through September 18, 2020 (Predecessor), and $6.3 million during 2019 (Predecessor).
v3.22.0.1
Stock Compensation
12 Months Ended
Dec. 31, 2021
Share-based Payment Arrangement [Abstract]  
Stock Compensation
Note 11. Stock Compensation

Below is a description of stock compensation relating to both the Predecessor periods (2019 and January 1, 2020 through September 18, 2020), and the Successor periods (September 19, 2020 through December 31, 2020 and 2021). All stock compensation plans and awards in effect during the Predecessor periods were cancelled upon emergence of the Company from its Chapter 11 Restructuring on September 18, 2020. The plans and awards described below which are designated as Successor
plans or awards are the only such plans and awards in effect as of December 31, 2021. Each of the plans and awards described below are designated as either Predecessor or Successor, with the exception of the section labeled “Stock-Based Compensation Predecessor and Successor” which pertains to both Predecessor and Successor periods.

Stock-based Compensation – Predecessor and Successor

Stock-based compensation expense is included in “General and administrative expenses” in the Consolidated Statements of Operations.  Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets. Our accounting policy is to account for forfeitures as they occur.

The following table sets forth stock-based compensation costs for the periods indicated:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Stock-based compensation expense included in G&A$25,322 $8,212 $4,111 $12,470 
Stock-based compensation capitalized1,883 695 1,660 4,018 
Total cost of stock-based compensation arrangements$27,205 $8,907 $5,771 $16,488 
Income tax benefit recognized for stock-based compensation arrangements$6,331 $2,053 $1,028 $3,118 

Management Incentive Plan – Successor

In connection with our emergence from bankruptcy, the Plan provided for the adoption of a management incentive plan, the Denbury Inc. 2020 Omnibus Stock and Incentive Plan (the “LTIP”), effective as of the Emergence Date, through an amendment and restatement of the Denbury Resources Inc. Amended and Restated 2004 Omnibus Stock and Incentive Plan, as amended and restated as of March 26, 2020. The LTIP reserved 6.2 million shares of Denbury’s common stock for awards to officers, other employees, directors and other service providers. The LTIP provides for, among other things, the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, or any combination of the foregoing. On December 2, 2020, Denbury’s board of directors approved and ratified the LTIP, with initial awards covering 2.2 million shares of common stock granted on December 4, 2020. As of December 31, 2021, 3.9 million shares were available for future grants under the LTIP, all of which could be issued in the form of restricted stock units or performance stock units. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors. The LTIP will expire September 2030.

Restricted Stock Units – Successor

In December 2020, non-performance-based restricted stock unit (“RSU”) awards were granted to directors and a limited number of employees under the Successor’s LTIP. Holders of non-performance-based RSUs will receive shares of Successor common stock equal to the number of RSUs that have vested upon settlement. Non-performance-based RSUs generally vest ratably over a three-year period with delivery of the shares occurring at the end of the three-year period. Vested non-performance-based RSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying RSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. The grant-date fair value of the RSUs is based on the fair market value of our common stock on the date of grant.

As of December 31, 2021, there was $19.9 million of unrecognized compensation expense related to the Successor’s nonvested non-performance-based restricted stock unit grants.  This unrecognized compensation cost is expected to be
recognized over a weighted-average period of 1.9 years. The following is a summary of the total vesting date fair value of non-performance-based restricted stock units:
Year Ended
Dec. 31, 2021
In thousands
Fair value of restricted stock units vested
$31,073 

A summary of the status of our nonvested non-performance-based RSUs issued and the changes during the Successor period is presented below:
Number
of Awards
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 20201,219,867 $24.67 
Granted56,236 31.87 
Vested(405,311)24.80 
Forfeited(20,885)24.67 
Nonvested at December 31, 2021849,907 25.08 

Performance-Based Stock Units – Successor

In December 2020, the Successor Board of Directors granted performance stock unit (“PSU”) awards to a limited number of employees. The PSU awards had vesting parameters tied to the Company’s common stock trading prices and became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, delivery of the shares will not occur until the conclusion of the three-year performance period, December 4, 2023. Vested performance-based PSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying PSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP.

PSU awards are valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date.

As of December 31, 2021, there was no remaining unrecognized compensation expense related to the Successor’s PSU awards. The range of assumptions used in the Monte Carlo simulation valuation approach is as follows:
Successor
Period from Sept. 19, 2020 through
Dec. 31, 2020
 
Weighted average fair value of PSU awards granted$24.19 
Risk-free interest rate0.21 %
Expected life0.23 years
Expected volatility110.0 %
Dividend yield— %
A summary of the PSU awards activity during the Successor period is as follows:
Number
of Awards
Weighted
Average
Grant-Date Fair Value
Nonvested at December 31, 20201,021,222 $24.19 
Granted— — 
Vested(1,021,222)24.19 
Forfeited— — 
Nonvested at December 31, 2021— — 

The following is a summary of the total vesting date fair value of PSU awards:
Year Ended
Dec. 31, 2021
In thousands
Vesting date fair value of PSU awards
$45,077 

June 2020 Compensation Adjustments – Predecessor

In response to the then ongoing significant economic and market uncertainty affecting the oil and gas industry, in June 2020 the Predecessor and its Board of Directors and Compensation Committee implemented a revised compensation structure under which for 21 of the Company’s executives (including our named executive officers) and senior managers, all outstanding equity awards and 2020 targeted variable cash-based compensation were canceled and replaced with a cash retention incentive. In total, $15.2 million in cash retention incentives were prepaid to those employees in June 2020, with an obligation of the executives to repay up to 100% of the compensation (on an after-tax basis) if specified conditions were not satisfied. The Predecessor’s named executive officers’ cash retention incentives were earned 50% based on their continued employment for a period of up to 12 months and 50% based on achieving certain specified incentive metrics.

In accordance with FASC Topic 718, CompensationStock Compensation, we accounted for the transaction involving equity compensation as an award modification and reclassified the awards from equity to liability awards. As a result of the modification of the awards, unrecognized compensation at the time of modification was determined to be $18.7 million ($4.1 million of incremental compensation expense), which was higher than the $15.2 million cash payment, and was calculated as the greater of (i) grant date fair value of the previously-outstanding awards plus incremental compensation (defined as cash paid related to the cash retention incentive in excess of the modification date fair value of the previously-existing awards) or (ii) cash paid for the cash retention incentive for each award. The value was recognized as total compensation expense for each award over the service period. The compensation expense was recognized in “General and administrative expenses” in the Consolidated Statements of Operations during the period January 1, 2020 through September 18, 2020 (Predecessor). The accounting for the Predecessor’s remaining share-based compensation awards continued throughout the period covered by the Chapter 11 Restructuring, and upon cancellation of the awards, an additional $4.6 million of compensation expense was recognized during the Predecessor period ended September 18, 2020.

2004 Omnibus Stock and Incentive Plan – Predecessor

The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of March 26, 2020 (the “2004 Plan”), was an incentive plan that provided for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock appreciation rights settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock were authorized for issuance pursuant to the 2004 Plan.  In connection with our emergence from bankruptcy, all outstanding equity as of September 18, 2020 was cancelled.

Restricted Stock – Predecessor

During the Predecessor period, we granted non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards had the rights of owning non-restricted stock (including voting rights) except that the holders were not entitled to delivery of a portion thereof until certain
requirements were met.  Beginning in 2014, non-performance-based restricted stock awards provided the holders with forfeitable dividend equivalent rights which vested with the underlying shares. Non-performance-based restricted stock vested over a three-year vesting period, with the specific terms of vesting determined at the time of grant.

The following is a summary of the total vesting date fair value of non-performance-based restricted stock:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Fair value of restricted stock vested$707 $5,743 

In connection with our emergence from bankruptcy, all restricted stock outstanding as of September 18, 2020 was cancelled and there was no remaining compensation cost to be recognized in future periods related to nonvested non-performance-based restricted stock arrangements.

Performance-Based Equity Awards – Predecessor

The Predecessor’s Compensation Committee of the Board of Directors annually granted performance-based equity awards to Denbury’s officers.  Performance-based awards generally vested over 3.25 years for awards granted in 2019 and 2020. The number of performance-based shares earned (and eligible to vest) during the performance period was dependent upon: (1) the level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of the Predecessor’s stock relative to that of a designated peer group (“Performance-Based TSR Awards”).

Performance-Based Operational Awards were valued using the fair market value of the Predecessor’s stock, and Performance-Based TSR Awards were valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) is as follows:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
 
Weighted average fair value of Performance-Based TSR Awards granted$0.15 $1.95 
Risk-free interest rate0.27 %2.27 %
Expected life3.0 years3.0 years
Expected volatility89.6 %77.2 %
Dividend yield— %— %

The following is a summary of the total vesting date fair value of performance-based equity awards for the Predecessor:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Vesting date fair value of Performance-Based Operational Awards$— $— 
Vesting date fair value of Performance-Based TSR Awards79 2,783 
v3.22.0.1
Commodity Derivative Contracts
12 Months Ended
Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Commodity Derivative Contracts
Note 12. Commodity Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Successor Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we have no further hedging requirements under the Successor Bank Credit Agreement.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Successor Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of December 31, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
MonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)
Range(1)
 Weighted Average Price
SwapFloorCeiling
Oil Contracts:
2022 Fixed-Price Swaps
Jan – JunNYMEX15,500$42.65 58.15 $49.01 $— $— 
July – DecNYMEX9,00050.13 60.35 56.35 — — 
2022 Collars
Jan – JunNYMEX11,000$47.50 70.75 $— $49.77 $64.31 
July – DecNYMEX10,00047.50 70.75 — 49.75 64.18 

(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and the highest ceiling price for all open contracts for the period presented.
v3.22.0.1
Fair Value Measurements
12 Months Ended
Dec. 31, 2021
Fair Value Disclosures [Abstract]  
Fair Value Measurements
Note 13. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”).  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of
observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the observability of those inputs.  The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet).  Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions.  We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020:
 Fair Value Measurements Using:
Quoted Prices
in Active
Markets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
In thousands(Level 1)(Level 2)(Level 3)Total
December 31, 2021    
Liabilities
Oil derivative contracts – current$— $(134,509)$— $(134,509)
Oil derivative contracts – long-term— — — — 
Total Liabilities$— $(134,509)$— $(134,509)
December 31, 2020    
Assets
Oil derivative contracts – current$— $187 $— $187 
Total Assets$— $187 $— $187 
Liabilities
Oil derivative contracts – current$— $(53,865)$— $(53,865)
Oil derivative contracts – long-term— (5,087)— (5,087)
Total Liabilities$— $(58,952)$— $(58,952)
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated Statements of Operations.

Other Fair Value Measurements

The carrying value of our loans under our Successor Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods.  The estimated fair value of the principal amount of our debt as of December 31, 2021 and 2020, excluding pipeline financing obligations, was $35.0 million and $70.0 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
v3.22.0.1
Commitments and Contingencies
12 Months Ended
Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Note 14. Commitments and Contingencies

Commitments

We have entered into long-term commitments to purchase CO2 that are either non-cancelable or cancelable only upon the occurrence of specified future events.  The commitments continue for up to 7 years.  The price we will pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil.  In addition, we have a processing fee contract related to our overriding royalty interest in the CO2 at LaBarge Field. Our annual commitment under these contracts could range from $39 million to $46 million in 2022, assuming a $70 per Bbl NYMEX oil price and declines in future years as the CO2 purchase contract commitments expire.

We are party to long-term contracts that require us to deliver CO2 to our customers who are industrial end-users of CO2 or EOR customers at various contracted prices. Based upon the maximum daily contract quantities as stated in the industrial contracts, total amounts deliverable to these customers could be up to 572 Bcf of CO2 over the next 13 years.

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties.  We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

Other Contingencies

We are subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe.  In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.
v3.22.0.1
Additional Balance Sheet Details
12 Months Ended
Dec. 31, 2021
Text Block [Abstract]  
Additional Balance Sheet Details
Note 15. Additional Balance Sheet Details

Rollforward of Allowance for Doubtful Accounts
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Beginning balance$23,206 $22,146 $17,137 $17,070 
Provision for doubtful accounts826 1,060 5,297 68 
Write-offs(5,085)— (288)(1)
Ending balance$18,947 $23,206 $22,146 $17,137 

Accounts Payable and Accrued Liabilities
Successor
In thousandsDecember 31, 2021December 31, 2020
Accrued lease operating expenses$27,901 $21,294 
Accrued derivative settlements27,336 3,908 
Accounts payable25,700 18,629 
Accrued compensation23,735 7,512 
Accrued exploration and development costs18,936 1,861 
Accrued asset retirement obligations – current18,373 6,943 
Taxes payable14,453 17,221 
Accrued general and administrative expenses2,250 21,825 
Other32,914 13,478 
Total$191,598 $112,671 
v3.22.0.1
Supplemental Cash Flow Information
12 Months Ended
Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information
Note 16. Supplemental Cash Flow Information

Supplemental Cash Flow Information
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Supplemental cash flow information   
Cash paid for interest, expensed$4,227 $813 $29,357 $72,842 
Cash paid for interest, capitalized4,585 1,261 22,885 36,671 
Cash paid for interest, treated as a reduction of debt— — 46,417 85,303 
Cash paid for income taxes184 — 453 2,361 
Cash received from income tax refunds10,457 1,932 9,820 
Noncash investing and financing activities  
Increase in asset retirement obligations112,760 23,398 4,328 13,560 
Increase (decrease) in liabilities for capital expenditures35,679 1,867 (12,809)(17,740)
Conversion of convertible senior notes into common stock— — 11,501 — 
v3.22.0.1
Nature of Operations and Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2021
Accounting Policies [Abstract]  
Organization and Nature of Operations
Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. The Company is differentiated by our focus on CO2 EOR and the emerging CCUS industry, supported by the Company’s CO2 EOR technical and operational expertise and extensive CO2 pipeline infrastructure.

As further described in Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code below, Denbury Inc. became the successor reporting company of Denbury Resources Inc. (the “Predecessor”) upon the Predecessor’s emergence from bankruptcy on September 18, 2020. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc., and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol DEN.
Principles of Reporting and Consolidation
Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with GAAP and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  All intercompany balances and transactions have been eliminated.
Use Of Estimates
Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and
natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; (8) estimates made in the calculation of income taxes; (9) estimates made in determining the fair values for purchase price allocations; and (10) fair value estimates including estimates of reorganization value, enterprise value, and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.  While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Reclassifications
Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported total revenues, expenses, net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Cash, Cash Equivalents, and Restricted Cash
Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows:
Successor
In thousandsDecember 31, 2021December 31, 2020
Cash and cash equivalents$3,671 $518 
Restricted cash, current— 1,000 
Restricted cash, long-term46,673 40,730 
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows$50,344 $42,248 
Oil and Natural Gas Properties
Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic.  Proceeds
received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant.

Depletion.  The costs capitalized, including production equipment and future development costs, are depleted using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million during the year ended December 31, 2019, whereby these costs were transferred to the full cost amortization base. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 coronavirus pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting, for additional information).

Write-Down of Oil and Natural Gas Properties.  The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.  The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.  Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional CO2 capital costs to develop the proved oil and natural gas reserves.  Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $63.86 at December 31, 2021, $35.84 at December 31, 2020, $40.08 at September 18, 2020, and $55.55 at December 31, 2019. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. Primarily as a result of the commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. We did not record any ceiling test write-downs during the 2019 Predecessor period.

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
 
Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs until we are able to recognize proved reserves associated with the development project.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and any previously deferred unevaluated development costs become subject to depletion.
Property, Plant, and Equipment Policy
CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 operating and discovery expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO2 (see Tertiary Injection Costs above for further discussion).

Costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets.  Capitalized CO2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.

Pipelines

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years. Capitalized costs include $22.4 million of CO2 pipelines as of December 31, 2021, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2021.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life.  Vehicles are generally depreciated over a useful life of one to five years, furniture and fixtures over a life of one to ten years, and computer equipment and software are generally depreciated over a useful life of one to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.
Intangible Assets
Intangible Assets

Our intangible assets subject to amortization represent amounts assigned in fresh start accounting to long-term contracts to sell CO2 to industrial customers. We amortize the CO2 contract intangible assets on a straight-line basis over their estimated useful lives, which range from seven to 14 years. Total amortization expense for our intangible assets was $9.1 million during the year ended December 31, 2021, $2.7 million during the Successor period September 19, 2020 through December 31, 2020,
$1.7 million for the Predecessor period January 1, 2020 through September 18, 2020, and $2.4 million during the year ended 2019. The following table summarizes the carrying value of our intangible assets as of December 31, 2021 and 2020:
Successor
In thousandsDecember 31, 2021December 31, 2020
Long-term contracts to sell CO2 to industrial customers
$97,943 $97,943 
Other intangibles2,179 2,167 
Accumulated amortization(11,874)(2,748)
Net book value$88,248 $97,362 

As of December 31, 2021, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
In thousands 
2022$9,120 
20239,117 
20249,117 
20259,117 
20269,117 
Impairment Assessment of Long-Lived Assets
Impairment Assessment of Long-Lived Assets

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO2 properties and pipelines, and for the Successor period also included long-term contracts to sell CO2 to industrial customers.

We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2021, 2020 or 2019.
Asset Retirement Obligations
Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool.

Asset retirement obligations are estimated at the present value of expected future net cash flows.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.
Commodity Derivative Contracts
Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  Our derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change.
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Successor Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we have no further hedging requirements under the Successor Bank Credit Agreement.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Successor Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
Concentrations of Credit Risk
Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders).  There are no margin requirements with the counterparties of our derivative contracts.
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We would not expect the loss of any purchaser to have a material adverse effect upon our operations.
Income Taxes
Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Uncertain Tax Positions We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income per Common Share
Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units, nonvested performance stock units, and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and convertible senior notes.

The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Numerator
Net income (loss) – basic$56,002 $(50,658)$(1,432,578)$216,959 
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax— — — 14,134 
Net income (loss) – diluted$56,002 $(50,658)$(1,432,578)$231,093 
Denominator
Weighted average common shares outstanding – basic50,918 50,000 495,560 459,524 
Effect of potentially dilutive securities  
Restricted stock units762 — — — 
Warrants2,138 — — — 
Restricted stock and performance-based equity awards— — — 2,396 
Convertible senior notes(1)
— — — 48,421 
Weighted average common shares outstanding – diluted53,818 50,000 495,560 510,341 

(1)For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Predecessor’s common stock issuable upon full conversion of the convertible senior notes which were issued on June 19, 2019 (see Note 8, Long-Term Debt – 2019 Predecessor Debt Reduction Transactions).

For each of the periods from September 19, 2020 through December 31, 2020 (Successor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 50.0 million for the period September 19, 2020 through December 31, 2020 and 584.4 million for the period January 1, 2020 through September 18, 2020, if the Company had recognized net income during those periods.

Basic weighted average common shares during the year ended December 31, 2021 includes 1,383,144 performance-based and restricted stock units which are fully vested as of December 31, 2021. Although vesting criteria for these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023. During the Predecessor periods, basic weighted average common shares includes restricted stock that vested during the periods.

For purposes of calculating diluted weighted average common shares for the years ended December 31, 2021 and 2019, the nonvested restricted stock units, nonvested restricted stock and performance-based equity awards, along with unexercised
warrants are included in the computation using the treasury stock method, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods.

The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the year ended December 31, 2021, the period September 19, 2020 through December 31, 2020, and the year ended December 31, 2019, as their effect would have been antidilutive, as of the respective dates:
SuccessorPredecessor
In thousandsDecember 31, 2021December 31, 2020December 31, 2019
Restricted stock units— 1,220 — 
Warrants— 5,526 — 
Stock appreciation rights— — 1,981 
Restricted stock and performance-based equity awards— — 4,445 
Environmental and Litigation Contingencies
Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.  Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.
Recent Accounting Pronouncements
Recent Accounting Pronouncements

Recently Adopted

Income Taxes. In December 2019, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
Revenue Recognition
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition:

Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the
contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains control (the identified performance obligation is satisfied).

Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary.

Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets.

In addition to revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts, in certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.
Leases We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 14 years, with certain land leases having remaining terms up to 48 years.  Leases with a term of 12 months or less are not recorded on our balance sheet.The majority of our leases contain renewal options, typically exercisable at our sole discretion. At emergence, we recorded right-of-use assets and liabilities based on the fair value of lease payments and utilized our incremental borrowing rate based on information available at the Emergence Date.We account for lease and nonlease components in a contract as a single lease component for all asset classes. Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term.
Stock Compensation
Restricted Stock Units – Successor

In December 2020, non-performance-based restricted stock unit (“RSU”) awards were granted to directors and a limited number of employees under the Successor’s LTIP. Holders of non-performance-based RSUs will receive shares of Successor common stock equal to the number of RSUs that have vested upon settlement. Non-performance-based RSUs generally vest ratably over a three-year period with delivery of the shares occurring at the end of the three-year period. Vested non-performance-based RSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying RSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. The grant-date fair value of the RSUs is based on the fair market value of our common stock on the date of grant.
PSU awards are valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date.
Restricted Stock – Predecessor

During the Predecessor period, we granted non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards had the rights of owning non-restricted stock (including voting rights) except that the holders were not entitled to delivery of a portion thereof until certain
requirements were met.  Beginning in 2014, non-performance-based restricted stock awards provided the holders with forfeitable dividend equivalent rights which vested with the underlying shares. Non-performance-based restricted stock vested over a three-year vesting period, with the specific terms of vesting determined at the time of grant.
Performance-Based Equity Awards – Predecessor

The Predecessor’s Compensation Committee of the Board of Directors annually granted performance-based equity awards to Denbury’s officers.  Performance-based awards generally vested over 3.25 years for awards granted in 2019 and 2020. The number of performance-based shares earned (and eligible to vest) during the performance period was dependent upon: (1) the level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of the Predecessor’s stock relative to that of a designated peer group (“Performance-Based TSR Awards”).
Performance-Based Operational Awards were valued using the fair market value of the Predecessor’s stock, and Performance-Based TSR Awards were valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date.
Fair Value Measurements The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”).  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs can be readily observable, market corroborated or generally unobservable.  We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of
observable inputs and minimize the use of unobservable inputs.  We are able to classify fair value balances based on the observability of those inputs.  The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date.  Level 2 includes those financial instruments that are valued using models or other valuation methodologies.  Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet).  Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures.  Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions.  We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
v3.22.0.1
Nature of Operations and Summary of Significant Accounting Policies (Tables)
12 Months Ended
Dec. 31, 2021
Accounting Policies [Abstract]  
Schedule of cash, cash equivalents, and restricted cash The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows:
Successor
In thousandsDecember 31, 2021December 31, 2020
Cash and cash equivalents$3,671 $518 
Restricted cash, current— 1,000 
Restricted cash, long-term46,673 40,730 
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows$50,344 $42,248 
Schedule of intangible assets The following table summarizes the carrying value of our intangible assets as of December 31, 2021 and 2020:
Successor
In thousandsDecember 31, 2021December 31, 2020
Long-term contracts to sell CO2 to industrial customers
$97,943 $97,943 
Other intangibles2,179 2,167 
Accumulated amortization(11,874)(2,748)
Net book value$88,248 $97,362 
Schedule of future amortization expense of intangible assets
As of December 31, 2021, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
In thousands 
2022$9,120 
20239,117 
20249,117 
20259,117 
20269,117 
Schedule of earnings per share, basic and diluted reconciliation
The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Numerator
Net income (loss) – basic$56,002 $(50,658)$(1,432,578)$216,959 
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax— — — 14,134 
Net income (loss) – diluted$56,002 $(50,658)$(1,432,578)$231,093 
Denominator
Weighted average common shares outstanding – basic50,918 50,000 495,560 459,524 
Effect of potentially dilutive securities  
Restricted stock units762 — — — 
Warrants2,138 — — — 
Restricted stock and performance-based equity awards— — — 2,396 
Convertible senior notes(1)
— — — 48,421 
Weighted average common shares outstanding – diluted53,818 50,000 495,560 510,341 

(1)For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Predecessor’s common stock issuable upon full conversion of the convertible senior notes which were issued on June 19, 2019 (see Note 8, Long-Term Debt – 2019 Predecessor Debt Reduction Transactions).
Schedule of antidilutive securities excluded from computation of earnings per share
The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the year ended December 31, 2021, the period September 19, 2020 through December 31, 2020, and the year ended December 31, 2019, as their effect would have been antidilutive, as of the respective dates:
SuccessorPredecessor
In thousandsDecember 31, 2021December 31, 2020December 31, 2019
Restricted stock units— 1,220 — 
Warrants— 5,526 — 
Stock appreciation rights— — 1,981 
Restricted stock and performance-based equity awards— — 4,445 
v3.22.0.1
Fresh Start Accounting (Tables)
12 Months Ended
Dec. 31, 2021
Reconciliation of Reorganization Value
The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Less: Total debt(231,022)
Equity value$1,095,419 

The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted entity) and total reorganization value:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Plus: Current liabilities excluding current maturities of long-term debt239,738 
Plus: Non-interest-bearing noncurrent liabilities185,228 
Reorganization value of the reconstituted Successor$1,751,407 
Schedule Of Reorganization Adjustments
The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
Debtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 
Schedule of Fresh-Start Adjustments
The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants.
As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Assets
Current assets 
Cash and cash equivalents$73,372 $(27,787)
(1)
$— $45,585 
Restricted cash— 10,662 
(2)
— 10,662 
Accrued production receivable112,832 — — 112,832 
Trade and other receivables, net36,221 — — 36,221 
Derivative assets32,635 — — 32,635 
Other current assets12,968 (539)
(3)
— 12,429 
Total current assets268,028 (17,664)— 250,364 
Property and equipment 
Oil and natural gas properties (using full cost accounting)
Proved properties11,723,546 — (10,941,313)782,233 
Unevaluated properties650,553 — (538,570)111,983 
CO2 properties
1,198,515 — (1,011,169)187,346 
Pipelines2,339,864 — (2,207,246)132,618 
Other property and equipment201,565 — (104,152)97,413 
Less accumulated depletion, depreciation, amortization and impairment(12,864,141)— 12,864,141 — 
Net property and equipment3,249,902 — (1,938,309)
(10)
1,311,593 
Operating lease right-of-use assets1,774 — 69 
(10)
1,843 
Derivative assets501 — — 501 
Intangible assets, net20,405 — 79,678 
(11)
100,083 
Other assets81,809 8,241 
(4)
(3,027)
(12)
87,023 
Total assets$3,622,419 $(9,423)$(1,861,589)$1,751,407 
As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Liabilities and Stockholders’ Equity
Current liabilities 
Accounts payable and accrued liabilities$67,789 $102,793 
(5)
$3,738 
(13)
$174,320 
Oil and gas production payable39,372 16,705 
(6)
— 56,077 
Derivative liabilities8,613 — — 8,613 
Current maturities of long-term debt— 73,199 
(6)
364 
(14)
73,563 
Operating lease liabilities— 757 
(6)
(29)
(10)
728 
Total current liabilities115,774 193,454 4,073 313,301 
Long-term liabilities 
Long-term debt, net of current portion140,000 42,610 
(6)
(25,151)
(14)
157,459 
Asset retirement obligations2,727 180,408 
(6)
(24,697)
(10)
158,438 
Derivative liabilities295 — — 295 
Deferred tax liabilities, net— 417,951 
(6)(15)
(414,120)
(15)
3,831 
Operating lease liabilities— 515 
(6)
10 
(10)
525 
Other liabilities— 3,540 
(6)
18,599 
(16)
22,139 
Total long-term liabilities not subject to compromise143,022 645,024 (445,359)342,687 
Liabilities subject to compromise2,823,506 (2,823,506)
(6)
— — 
Commitments and contingencies (Note 14)
Stockholders’ equity
Predecessor preferred stock— — — — 
Predecessor common stock510 (510)
(7)
— — 
Predecessor paid-in capital in excess of par2,764,915 (2,764,915)
(7)
— — 
Predecessor treasury stock, at cost(6,202)6,202 
(7)
— — 
Successor preferred stock— — — — 
Successor common stock— 50 
(8)
— 50 
Successor paid-in capital in excess of par— 1,095,369 
(8)
— 1,095,369 
Accumulated deficit(2,219,106)3,639,409 
(9)
(1,420,303)
(17)
— 
Total stockholders equity
540,117 1,975,605 (1,420,303)1,095,419 
Total liabilities and stockholders’ equity$3,622,419 $(9,423)$(1,861,589)$1,751,407 

Reorganization Adjustments

(1)Represents the net cash payments that occurred on the Emergence Date as follows:
In thousands
Sources:
Cash proceeds from Successor Bank Credit Agreement$140,000 
Total cash proceeds140,000 
Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility(140,000)
Retained professional service provider fees paid to escrow account(10,662)
Non-retained professional service provider fees paid(7,420)
Accrued interest and fees on DIP Facility(1,464)
Debt issuance costs related to Successor Bank Credit Agreement(8,241)
Total cash uses(167,787)
Net uses$(27,787)
(2)Represents the transfer of funds to a restricted cash account utilized for the payment of fees to retained professional service providers assisting in the bankruptcy process.

(3)Represents the write-off of costs related to the DIP Facility and a run-off policy for directors’ and officers’ insurance coverage, partially offset by the recording of prepaid amounts for non-retained professional service provider fees.

(4)Represents debt issuance costs related to the Successor Bank Credit Agreement.

(5)Adjustments to accounts payable and accrued liabilities as follows:
In thousands
Accrual of professional service provider fees$2,826 
Payment of accrued interest and fees on DIP Facility(1,464)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise101,431 
Accounts payable and accrued liabilities$102,793 

(6)Liabilities subject to compromise were settled as follows in accordance with the Plan:
In thousands
Liabilities subject to compromise prior to the Emergence Date:
Settled liabilities subject to compromise
Senior secured second lien notes$1,629,457 
Convertible senior notes234,015 
Senior subordinated notes251,480 
Total settled liabilities subject to compromise2,114,952 
Reinstated liabilities subject to compromise
Current maturities of long-term debt73,199 
Accounts payable and accrued liabilities101,431 
Oil and gas production payable16,705 
Operating lease liabilities, current757 
Long-term debt, net of current portion42,610 
Asset retirement obligations180,408 
Deferred tax liabilities289,389 
Operating lease liabilities, long-term515 
Other long-term liabilities3,540 
Total reinstated liabilities subject to compromise708,554 
Total liabilities subject to compromise2,823,506 
Issuance of New Common Stock to second lien note holders(1,014,608)
Issuance of New Common Stock to convertible note holders(53,400)
Issuance of series A warrants to convertible note holders(15,683)
Issuance of series B warrants to senior subordinated note holders (6,398)
Reinstatement of liabilities subject to compromise(708,553)
Gain on settlement of liabilities subject to compromise$1,024,864 

(7)Represents the cancellation of the Predecessor’s common stock, treasury stock, and related components of the Predecessor’s paid-in capital in excess of par. Paid-in capital in excess of par includes $4.6 million as a result of terminated Predecessor stock compensation plans.
(8)Represents the Successor’s common stock and additional paid-in capital as follows:
In thousands
Capital in excess of par value of 47,499,999 issued and outstanding shares of New Common Stock issued to holders of the senior secured second lien note claims$1,014,608 
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock issued to holders of the convertible senior note claims53,400 
Fair value of series A warrants issued to convertible senior note holders15,683 
Fair value of series B warrants issued to senior subordinated note holders6,398 
Fair value of series B warrants issued to Predecessor equity holders5,330 
Total change in Successor common stock and additional paid-in capital1,095,419 
Less: Par value of Successor common stock(50)
Change in Successor additional paid-in capital$1,095,369 

(9)Reflects the cumulative net impact of the effects on accumulated deficit as follows:
In thousands
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock$2,763,824 
Gain on settlement of liabilities subject to compromise1,024,864 
Acceleration of Predecessor stock compensation expense(4,601)
Recognition of tax expenses related to reorganization adjustments(128,556)
Professional service provider fees recognized at emergence(9,700)
Issuance of series B warrants to Predecessor equity holders(5,330)
Other(1,092)
Net impact to Predecessor accumulated deficit$3,639,409 

Fresh Start Adjustments

(10)Reflects fair value adjustments to our (i) oil and natural gas properties, CO2 properties, pipelines, and other property and equipment, as well as the elimination of accumulated depletion, depreciation, and amortization, (ii) operating lease right-of-use assets and liabilities, and (iii) asset retirement obligations.

(11)Reflects fair value adjustments to our long-term contracts to sell CO2 to industrial customers.

(12)Reflects fair value adjustments to our other assets as follows:
In thousands
Fair value adjustment for CO2 and oil pipeline line-fill
$(3,698)
Fair value adjustments for escrow accounts671 
Fair value adjustments to other assets$(3,027)

(13)Reflects fair value adjustments to accounts payable and accrued liabilities as follows:
In thousands
Fair value adjustment for the current portion of an unfavorable vendor contract$3,500 
Fair value adjustment for the current portion of Predecessor asset retirement obligation689 
Write-off accrued interest on NEJD pipeline financing(451)
Fair value adjustments to accounts payable and accrued liabilities$3,738 
(14)Represents adjustments to current and long-term maturities of debt associated with pipeline lease financings. The cumulative effect is as follows:
In thousands
Fair value adjustment for Free State pipeline lease financing$(24,699)
Fair value adjustment for NEJD pipeline lease financing(88)
Fair value adjustments to current and long-term maturities of debt$(24,787)

Our pipeline lease financings were restructured in late October 2020 (see Note 8, Long-Term DebtRestructuring of Pipeline Financing Transactions).

(15)Represents (i) adjustment to deferred taxes, including the recognition of tax expenses related to reorganization adjustments as a result of the cancellation of debt and retaining tax attributes for the Successor and the reinstatement of deferred tax liabilities subject to compromise totaling $128.6 million and (ii) adjustments to deferred tax liabilities related to fresh start accounting of $414.1 million.

(16)Represents a fair value adjustment for the long-term portion of an unfavorable vendor contract.

(17)Represents the cumulative effect of the fresh start accounting adjustments discussed above.
v3.22.0.1
Acquisition and Divestitures (Tables)
12 Months Ended
Dec. 31, 2021
Business Combinations [Abstract]  
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:
In thousands
Consideration:
Cash consideration$10,906 
Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties60,101 
Other property and equipment1,685 
Asset retirement obligations(39,794)
Contingent consideration(5,320)
Other liabilities(5,766)
Fair value of net assets acquired$10,906 
v3.22.0.1
Revenue Recognition (Tables)
12 Months Ended
Dec. 31, 2021
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue
The following table summarizes our revenues by product type:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Oil sales $1,148,022 $199,769 $489,251 $1,205,083 
Natural gas sales11,933 1,339 2,850 6,937 
CO2 sales and transportation fees
44,175 9,419 21,049 34,142 
Oil marketing revenues38,742 5,376 8,543 14,198 
Total revenues$1,242,872 $215,903 $521,693 $1,260,360 
v3.22.0.1
Leases (Tables)
12 Months Ended
Dec. 31, 2021
Leases [Abstract]  
Schedule of Lease Assets and Liabilities The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our office leases:
Successor
In thousandsDecember 31, 2021December 31, 2020
Operating leases
Operating lease right-of-use assets$19,502 $20,342 
Operating lease liabilities – current$4,677 $1,350 
Operating lease liabilities – long-term17,094 19,460 
Total operating lease liabilities$21,771 $20,810 
Schedule of Weighted Average Lease Terms and Discount Rates The following weighted average remaining lease terms and discount rates related to our outstanding operating leases:
Successor
December 31, 2021December 31, 2020
Weighted average remaining lease term5.2 years6.3 years
Weighted average discount rate5.4 %5.6 %
Schedule of Lease Costs The following table summarizes the components of lease costs and sublease income:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousandsIncome Statement
Operating lease costGeneral and administrative expenses$4,102 $872 $5,683 $8,924 
Lease operating expenses655 158 214 58 
CO2 operating and discovery expenses
50 14 37 
$4,807 $1,044 $5,934 $8,987 
Finance lease cost
Amortization of right-of-use assetsDepletion, depreciation, and amortization$— $$$1,188 
Interest on lease liabilitiesInterest expense— 40 
Total finance lease cost$— $$12 $1,228 
Variable lease cost$670 $258 $3,688 $4,852 
Sublease incomeGeneral and administrative expenses$— $100 $2,584 $4,127 
Supplemental Cash Flow Information Related to Leases
Our statement of cash flows included the following activity related to our operating and finance leases:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases$2,830 $341 $7,341 $10,995 
Operating cash flows from interest on finance leases— 40 
Financing cash flows from finance leases— 78 10 1,275 
Right-of-use assets obtained in exchange for lease obligations
Operating leases2,683 19,902 1,049 415 
Finance leases— — 162 — 
Schedule of Maturities of Operating Lease Liabilities
The following table summarizes by year the maturities of our lease liabilities as of December 31, 2021:
Operating
In thousandsLeases
2022$5,705 
20234,712 
20244,138 
20254,177 
20264,203 
Thereafter2,326 
Total minimum lease payments25,261 
Less: Amount representing interest(3,490)
Present value of minimum lease liabilities$21,771 
v3.22.0.1
Asset Retirement Obligations (Tables)
12 Months Ended
Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]  
Changes In Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Beginning asset retirement obligations$186,281 $163,368 $181,760 
Liabilities incurred and assumed during period43,701 738 736 
Revisions in estimated retirement obligations69,059 22,660 3,592 
Liabilities settled and sold during period(10,783)(3,439)(10,041)
Accretion expense14,353 2,954 11,329 
Fresh start accounting adjustment— — (24,008)
Ending asset retirement obligations302,611 186,281 163,368 
Less: current asset retirement obligations(1)
(18,373)(6,943)(4,930)
Long-term asset retirement obligations$284,238 $179,338 $158,438 

(1)Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.
v3.22.0.1
Unevaluated Property (Tables)
12 Months Ended
Dec. 31, 2021
Property, Plant and Equipment [Abstract]  
Summary of unevaluated properties excluded from oil and natural gas properties being amortized
A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2021, and the year in which the costs were incurred follows:
 December 31, 2021
 Costs Incurred During: 
In thousands2021Successor 2020
Fresh Start Adjustments (Sept. 18, 2020)(1)
Total
Property acquisition costs$— $— $68,103 $68,103 
Exploration and development39,481 46 — 39,527 
Capitalized interest3,576 963 — 4,539 
Total$43,057 $1,009 $68,103 $112,169 

(1)Reflects the carrying values of our unevaluated properties as a result of the application of fresh start accounting upon emergence from bankruptcy (see Note 2, Fresh Start Accounting, for additional information) that remain in unevaluated properties as of December 31, 2021.
v3.22.0.1
Long-Term Debt (Tables)
12 Months Ended
Dec. 31, 2021
Debt Disclosure [Abstract]  
Components of long-term debt
The table below reflects long-term debt outstanding as of December 31, 2021 and 2020:
 Successor
In thousandsDecember 31, 2021December 31, 2020
Senior Secured Bank Credit Agreement$35,000 $70,000 
Pipeline financings— 68,008 
Total debt principal balance35,000 138,008 
Less: current maturities of long-term debt— (68,008)
Long-term debt$35,000 $70,000 
Indebtedness repayable over the next five years and thereafter
At December 31, 2021, our indebtedness is payable over the next five years and thereafter as follows:
In thousands 
2022$— 
2023— 
202435,000 
2025— 
2026— 
Thereafter— 
Total indebtedness$35,000 
v3.22.0.1
Income Taxes (Tables)
12 Months Ended
Dec. 31, 2021
Income Tax Disclosure [Abstract]  
Income Tax Provision (Benefit)
Our income tax provision (benefit) is as follows:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Current income tax expense (benefit)   
Federal$— $— $(6,407)$2,645 
State403 30 (853)1,236 
Total current income tax expense (benefit)403 30 (7,260)3,881 
Deferred income tax expense (benefit)   
Federal— — (319,011)89,950 
State364 (2,556)(89,858)10,521 
Total deferred income tax expense (benefit)364 (2,556)(408,869)100,471 
Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 
Deferred Tax Assets And Liabilities
Significant components of our deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
 Successor
In thousandsDecember 31, 2021December 31, 2020
Deferred tax assets  
Loss and tax credit carryforwards – state$54,943 $55,979 
Derivative contracts30,892 13,090 
Accrued liabilities and other reserves19,567 15,632 
Business credit carryforwards18,066 — 
Loss carryforwards – federal10,310 — 
Lease liabilities4,523 6,354 
Property and equipment2,613 59,207 
Other4,206 4,092 
Valuation allowances(125,462)(129,408)
Total deferred tax assets19,658 24,946 
Deferred tax liabilities  
CO2 and other contracts
(17,208)(20,030)
Operating lease right-of-use assets(4,088)(6,190)
Total deferred tax liabilities(21,296)(26,220)
Total net deferred tax liability$(1,638)$(1,274)
Income Tax Provision (Benefit) Rate Reconciliation
Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Income tax provision calculated using the federal statutory income tax rate$11,921 $(11,169)$(388,228)$67,475 
State income taxes, net of federal income tax benefit450 (2,532)(86,937)7,435 
Tax shortfall (windfall) on stock-based compensation deduction(267)— (1,502)1,912 
Nondeductible compensation5,057 — — — 
Change in valuation allowance(2,928)9,653 19,344 26,122 
Enhanced oil recovery credits generated(14,272)— — — 
Tax attributes reduction – net of CODI exclusion— — 31,667 — 
Other806 1,522 9,527 1,408 
Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 
Tax Valuation Allowance  
Valuation Allowance [Line Items]  
Changes in Valuation Allowance The changes in our valuation allowance are detailed below:
SuccessorPredecessor
Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Beginning balance$129,408 $129,840 $77,215 $51,093 
Charges29,345 2,269 77,138 26,122 
Deductions(33,291)(2,701)(24,513)— 
Ending balance$125,462 $129,408 $129,840 $77,215 
v3.22.0.1
Stock Compensation (Tables)
12 Months Ended
Dec. 31, 2021
Stock Compensation  
Schedule of stock-based compensation costs
The following table sets forth stock-based compensation costs for the periods indicated:
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Stock-based compensation expense included in G&A$25,322 $8,212 $4,111 $12,470 
Stock-based compensation capitalized1,883 695 1,660 4,018 
Total cost of stock-based compensation arrangements$27,205 $8,907 $5,771 $16,488 
Income tax benefit recognized for stock-based compensation arrangements$6,331 $2,053 $1,028 $3,118 
Restricted Stock Units  
Stock Compensation  
Summary of the total vesting date fair value of equity awards The following is a summary of the total vesting date fair value of non-performance-based restricted stock units:
Year Ended
Dec. 31, 2021
In thousands
Fair value of restricted stock units vested
$31,073 
Schedule of nonvested restricted stock units activity
A summary of the status of our nonvested non-performance-based RSUs issued and the changes during the Successor period is presented below:
Number
of Awards
Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 20201,219,867 $24.67 
Granted56,236 31.87 
Vested(405,311)24.80 
Forfeited(20,885)24.67 
Nonvested at December 31, 2021849,907 25.08 
Performance Share Units  
Stock Compensation  
Summary of the total vesting date fair value of equity awards
The following is a summary of the total vesting date fair value of PSU awards:
Year Ended
Dec. 31, 2021
In thousands
Vesting date fair value of PSU awards
$45,077 
Summary of performance-based equity awards valuation assumptions The range of assumptions used in the Monte Carlo simulation valuation approach is as follows:
Successor
Period from Sept. 19, 2020 through
Dec. 31, 2020
 
Weighted average fair value of PSU awards granted$24.19 
Risk-free interest rate0.21 %
Expected life0.23 years
Expected volatility110.0 %
Dividend yield— %
Schedule of nonvested performance stock unit awards activity
A summary of the PSU awards activity during the Successor period is as follows:
Number
of Awards
Weighted
Average
Grant-Date Fair Value
Nonvested at December 31, 20201,021,222 $24.19 
Granted— — 
Vested(1,021,222)24.19 
Forfeited— — 
Nonvested at December 31, 2021— — 
Restricted Stock  
Stock Compensation  
Summary of the total vesting date fair value of equity awards
The following is a summary of the total vesting date fair value of non-performance-based restricted stock:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Fair value of restricted stock vested$707 $5,743 
Performance-Based Equity Awards  
Stock Compensation  
Summary of the total vesting date fair value of equity awards
The following is a summary of the total vesting date fair value of performance-based equity awards for the Predecessor:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Vesting date fair value of Performance-Based Operational Awards$— $— 
Vesting date fair value of Performance-Based TSR Awards79 2,783 
Summary of performance-based equity awards valuation assumptions The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) is as follows:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
 
Weighted average fair value of Performance-Based TSR Awards granted$0.15 $1.95 
Risk-free interest rate0.27 %2.27 %
Expected life3.0 years3.0 years
Expected volatility89.6 %77.2 %
Dividend yield— %— %
v3.22.0.1
Commodity Derivative Contracts (Tables)
12 Months Ended
Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Commodity derivative contracts not classified as hedging instruments
The following table summarizes our commodity derivative contracts as of December 31, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
MonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)
Range(1)
 Weighted Average Price
SwapFloorCeiling
Oil Contracts:
2022 Fixed-Price Swaps
Jan – JunNYMEX15,500$42.65 58.15 $49.01 $— $— 
July – DecNYMEX9,00050.13 60.35 56.35 — — 
2022 Collars
Jan – JunNYMEX11,000$47.50 70.75 $— $49.77 $64.31 
July – DecNYMEX10,00047.50 70.75 — 49.75 64.18 

(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and the highest ceiling price for all open contracts for the period presented.
v3.22.0.1
Fair Value Measurements (Tables)
12 Months Ended
Dec. 31, 2021
Fair Value Disclosures [Abstract]  
Fair value hierarchy of financial assets and liabilities
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020:
 Fair Value Measurements Using:
Quoted Prices
in Active
Markets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
In thousands(Level 1)(Level 2)(Level 3)Total
December 31, 2021    
Liabilities
Oil derivative contracts – current$— $(134,509)$— $(134,509)
Oil derivative contracts – long-term— — — — 
Total Liabilities$— $(134,509)$— $(134,509)
December 31, 2020    
Assets
Oil derivative contracts – current$— $187 $— $187 
Total Assets$— $187 $— $187 
Liabilities
Oil derivative contracts – current$— $(53,865)$— $(53,865)
Oil derivative contracts – long-term— (5,087)— (5,087)
Total Liabilities$— $(58,952)$— $(58,952)
v3.22.0.1
Additional Balance Sheet Details (Tables)
12 Months Ended
Dec. 31, 2021
Text Block [Abstract]  
Accounts Payable and Accrued Liabilities
Accounts Payable and Accrued Liabilities
Successor
In thousandsDecember 31, 2021December 31, 2020
Accrued lease operating expenses$27,901 $21,294 
Accrued derivative settlements27,336 3,908 
Accounts payable25,700 18,629 
Accrued compensation23,735 7,512 
Accrued exploration and development costs18,936 1,861 
Accrued asset retirement obligations – current18,373 6,943 
Taxes payable14,453 17,221 
Accrued general and administrative expenses2,250 21,825 
Other32,914 13,478 
Total$191,598 $112,671 
Trade and Other Receivables, Net  
Valuation Allowance [Line Items]  
Changes in Valuation Allowance
Rollforward of Allowance for Doubtful Accounts
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020 through
Dec. 31, 2020
Period from
Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Beginning balance$23,206 $22,146 $17,137 $17,070 
Provision for doubtful accounts826 1,060 5,297 68 
Write-offs(5,085)— (288)(1)
Ending balance$18,947 $23,206 $22,146 $17,137 
v3.22.0.1
Supplemental Cash Flow Information (Tables)
12 Months Ended
Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information
Supplemental Cash Flow Information
SuccessorPredecessor
 Year Ended
Dec. 31, 2021
Period from Sept. 19, 2020 through
Dec. 31, 2020
Period from Jan. 1, 2020 through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
In thousands
Supplemental cash flow information   
Cash paid for interest, expensed$4,227 $813 $29,357 $72,842 
Cash paid for interest, capitalized4,585 1,261 22,885 36,671 
Cash paid for interest, treated as a reduction of debt— — 46,417 85,303 
Cash paid for income taxes184 — 453 2,361 
Cash received from income tax refunds10,457 1,932 9,820 
Noncash investing and financing activities  
Increase in asset retirement obligations112,760 23,398 4,328 13,560 
Increase (decrease) in liabilities for capital expenditures35,679 1,867 (12,809)(17,740)
Conversion of convertible senior notes into common stock— — 11,501 — 
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2019
Dec. 31, 2018
Accounting Policies [Abstract]          
Cash and cash equivalents $ 3,671 $ 518 $ 45,585    
Restricted cash, current 0 1,000      
Restricted cash, long-term 46,673 40,730      
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 50,344 $ 42,248 $ 95,114 $ 33,045 $ 54,949
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Intangibles) (Details 1) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]    
Long-term contracts to sell CO2 to industrial customers $ 97,943 $ 97,943
Other intangibles 2,179 2,167
Accumulated amortization (11,874) (2,748)
Net book value $ 88,248 $ 97,362
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Estimated Amortization Expense for Intangibles) (Details 2)
$ in Thousands
Dec. 31, 2021
USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]  
2022 $ 9,120
2023 9,117
2024 9,117
2025 9,117
2026 $ 9,117
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Reconciliation of Weighted Average Shares Table) (Details 3) - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Numerator        
Net income (loss) - basic $ (50,658) $ (1,432,578) $ 56,002 $ 216,959
Interest on convertible senior notes including amortization of discount, net of tax 0 0 0 14,134
Net income (loss) - diluted $ (50,658) $ (1,432,578) $ 56,002 $ 231,093
Denominator        
Weighted average common shares outstanding – basic 50,000 495,560 50,918 459,524
Restricted stock units 0 0 762 0
Warrants 0 0 2,138 0
Restricted stock and performance-based equity awards 0 0 0 2,396
Convertible senior notes 0 0 0 48,421 [1]
Weighted average common shares outstanding – diluted 50,000 495,560 53,818 510,341
Predecessor common shares issuable upon full conversion of convertible senior notes       90,900
[1] For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Predecessor’s common stock issuable upon full conversion of the convertible senior notes which were issued on June 19, 2019 (see Note 8, Long-Term Debt – 2019 Predecessor Debt Reduction Transactions).
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Antidilutive Securities) (Details 4) - shares
shares in Thousands
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Restricted stock units      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Number of antidilutive equity-based instruments outstanding 0 1,220 0
Warrants      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Number of antidilutive equity-based instruments outstanding 0 5,526 0
Stock appreciation rights      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Number of antidilutive equity-based instruments outstanding 0 0 1,981
Restricted stock and performance-based equity awards      
Antidilutive Securities Excluded from Computation of Earnings Per Share      
Number of antidilutive equity-based instruments outstanding 0 0 4,445
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Plan of Reorganization) (Details Textuals) - USD ($)
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2020
Jul. 28, 2020
Plan of Chapter 11 Reorganization [Line Items]        
Principal amount of debt cancelled $ 2,100,000,000      
Successor common stock, shares authorized 250,000,000 250,000,000 250,000,000  
Successor common stock, par value $ 0.001 $ 0.001 $ 0.001  
Successor preferred stock, shares authorized 50,000,000 50,000,000 50,000,000  
Successor preferred stock, par value $ 0.001 $ 0.001 $ 0.001  
Number of warrants outstanding   5,200,000    
Lender commitments $ 575,000,000 $ 575,000,000    
Series A Warrants        
Plan of Chapter 11 Reorganization [Line Items]        
Number of warrants outstanding 2,631,579 2,600,000    
Exercise price of warrants $ 32.59 $ 32.59    
Series B Warrants        
Plan of Chapter 11 Reorganization [Line Items]        
Number of warrants outstanding 2,894,740 2,600,000    
Exercise price of warrants $ 35.41 $ 35.41    
Lenders under Predecessor Credit Facility        
Plan of Chapter 11 Reorganization [Line Items]        
Consenting percentage       100.00%
Second Lien Note Holders        
Plan of Chapter 11 Reorganization [Line Items]        
Consenting percentage       67.10%
Common stock, shares outstanding 47,499,999      
Equity percentage under plan of reorganization 95.00%      
Convertible Note Holders        
Plan of Chapter 11 Reorganization [Line Items]        
Consenting percentage       73.10%
Common stock, shares outstanding 2,500,000      
Equity percentage under plan of reorganization 5.00%      
Convertible Note Holders | Series A Warrants        
Plan of Chapter 11 Reorganization [Line Items]        
Percentage of warrants 100.00%      
Convertible Note Holders | Series A Warrants | Maximum        
Plan of Chapter 11 Reorganization [Line Items]        
Equity percentage under plan of reorganization 5.00%      
Subordinated Note Holders | Series B Warrants        
Plan of Chapter 11 Reorganization [Line Items]        
Percentage of warrants 54.55%      
Subordinated Note Holders | Series B Warrants | Maximum        
Plan of Chapter 11 Reorganization [Line Items]        
Equity percentage under plan of reorganization 3.00%      
Equity Holders | Series B Warrants        
Plan of Chapter 11 Reorganization [Line Items]        
Percentage of warrants 45.45%      
Equity Holders | Series B Warrants | Maximum        
Plan of Chapter 11 Reorganization [Line Items]        
Equity percentage under plan of reorganization 2.50%      
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Details Textuals 2)
3 Months Ended 9 Months Ended 12 Months Ended
Sep. 18, 2020
$ / Barrel
Mar. 31, 2021
USD ($)
$ / Barrel
Dec. 31, 2020
USD ($)
Sep. 18, 2020
USD ($)
Dec. 31, 2021
USD ($)
$ / Barrel
Dec. 31, 2020
USD ($)
$ / Barrel
Dec. 31, 2019
USD ($)
$ / Barrel
Property, Plant and Equipment [Line Items]              
Oil and Gas, Average Sale Price | $ / Barrel 40.08 36.40     63.86 35.84 55.55
Costs related to CO2 pipelines not placed into service         $ 22,400,000    
Amortization of intangible assets     $ 2,700,000 $ 1,700,000 9,100,000   $ 2,400,000
Ceiling test write-downs of oil and gas properties   $ 14,400,000 $ 1,006,000 996,658,000 $ 14,377,000   0
Number of reporting segments         1    
Impairments of unevaluated costs       $ 244,900,000     18,200,000
Impairment of long-lived assets         $ 0 $ 0 $ 0
Minimum              
Property, Plant and Equipment [Line Items]              
Useful life of intangible CO2 contracts         7 years    
Maximum              
Property, Plant and Equipment [Line Items]              
Useful life of intangible CO2 contracts         14 years    
Pipelines | Minimum              
Property, Plant and Equipment [Line Items]              
Useful life         20 years    
Pipelines | Maximum              
Property, Plant and Equipment [Line Items]              
Useful life         50 years    
Vehicles | Minimum              
Property, Plant and Equipment [Line Items]              
Useful life         1 year    
Vehicles | Maximum              
Property, Plant and Equipment [Line Items]              
Useful life         5 years    
Furniture and Fixtures | Minimum              
Property, Plant and Equipment [Line Items]              
Useful life         1 year    
Furniture and Fixtures | Maximum              
Property, Plant and Equipment [Line Items]              
Useful life         10 years    
Computer Equipment | Minimum              
Property, Plant and Equipment [Line Items]              
Useful life         1 year    
Computer Equipment | Maximum              
Property, Plant and Equipment [Line Items]              
Useful life         5 years    
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Major Customers) (Details Textuals 3) - Revenue Benchmark - Customer Concentration Risk
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Plains Marketing LP        
Product Information [Line Items]        
Revenue from major customer (percentage) 30.00% 30.00% 28.00% 32.00%
Hunt Crude Oil Company        
Product Information [Line Items]        
Revenue from major customer (percentage) 12.00% 12.00% 12.00% 11.00%
Marathon Petroleum Company        
Product Information [Line Items]        
Revenue from major customer (percentage) 13.00% 12.00% 11.00%  
Sunoco Inc        
Product Information [Line Items]        
Revenue from major customer (percentage)     11.00% 11.00%
v3.22.0.1
Nature of Ops and Sign. Acctg Policies (Weighted Avg Shares) (Details Textuals 4) - $ / shares
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Weighted average number of dilutive shares 50,000,000 495,560,000 53,818,000 510,341,000
Weighted average common shares outstanding – basic 50,000,000 495,560,000 50,918,000 459,524,000
Number of warrants outstanding     5,200,000  
Issued pursuant to exercise of warrants, shares     193,657  
Series A Warrants        
Number of warrants outstanding   2,631,579 2,600,000  
Exercise price of warrants   $ 32.59 $ 32.59  
Number of warrants exercised     11,694  
Series B Warrants        
Number of warrants outstanding   2,894,740 2,600,000  
Exercise price of warrants   $ 35.41 $ 35.41  
Number of warrants exercised     327,266  
Performance-based and restricted stock units        
Weighted average common shares outstanding – basic     1,383,144  
Net Income Scenario        
Weighted average number of dilutive shares 50,000,000 584,400,000    
v3.22.0.1
Fresh Start Accounting (Enterprise Value to Equity Value) (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2019
Dec. 31, 2018
Reorganizations [Abstract]          
Enterprise value     $ 1,280,856    
Cash and cash equivalents $ 3,671 $ 518 45,585    
Postconfirmation Debt     (231,022)    
Stockholders' Equity Attributable to Parent $ 1,135,390 $ 1,053,668 $ 1,095,419 $ 1,412,259 $ 1,141,777
v3.22.0.1
Fresh Start Accounting (Reconciliation of Reorganization Value) (Details 1) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Reorganizations [Abstract]      
Enterprise value     $ 1,280,856
Cash and cash equivalents $ 3,671 $ 518 45,585
Plus: Current liabilities excluding current maturities of long-term debt     239,738
Plus: Non-interest bearing noncurrent liabilities     185,228
Reorganization value of the reconstituted Successor     $ 1,751,407
v3.22.0.1
Fresh Start Accounting (Reorganization Items) (Details 2) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Reorganizations [Abstract]          
Gain on settlement of liabilities subject to compromise     $ (1,024,864)    
Fresh start accounting adjustments     1,834,423    
Professional service provider fees and other expenses     11,267    
Success fees for professional service providers     9,700    
Loss on rejected contracts and leases     10,989    
Valuation adjustments to debt classified as subject to compromise     757    
DIP credit agreement fees     3,107    
Acceleration of Predecessor stock compensation expense   $ 4,600 4,601    
Total reorganization items, net $ 0   $ 849,980 $ 0 $ 0
v3.22.0.1
Fresh Start Accounting (Condensed Consolidated Balance Sheet) (Details 3) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2019
Dec. 31, 2018
Fresh-Start Adjustment [Line Items]          
Cash and cash equivalents $ 3,671 $ 518 $ 45,585    
Restricted cash     10,662    
Accrued production receivable 143,365 91,421 112,832    
Trade and other receivables, net 19,270 19,682 36,221    
Derivative assets 0 187 32,635    
Prepaids 9,099 14,038 12,429    
Total current assets 175,405 126,846 250,364    
Proved properties 1,109,011 851,208 782,233    
Unevaluated properties 112,169 85,304 111,983    
CO2 properties 183,369 188,288 187,346    
Pipelines 224,394 133,485 132,618    
Other property and equipment 93,950 86,610 97,413    
Less accumulated depletion, depreciation, amortization and impairment (181,393) (41,095) 0    
Net property and equipment 1,541,500 1,303,800 1,311,593    
Operating lease right-of-use assets 19,502 20,342 1,843    
Derivative assets     501    
Intangible assets, net     100,083    
Other assets 78,298 86,408 87,023    
Total assets 1,902,953 1,634,758 1,751,407    
Accounts payable and accrued liabilities 191,598 112,671 174,320    
Oil and gas production payable     56,077    
Derivative liabilities 134,509 53,865 8,613    
Current maturities of long-term debt 0 68,008 73,563    
Operating lease liabilities 4,677 1,350 728    
Total current liabilities 406,683 285,059 313,301    
Long-term debt 35,000 70,000 157,459    
Asset retirement obligations 284,238 179,338 158,438    
Derivative liabilities 0 5,087 295    
Deferred tax liabilities, net 1,638 1,274 3,831    
Operating lease liabilities 17,094 19,460 525    
Other liabilities 22,910 20,872 22,139    
Total long-term liabilities not subject to compromise     342,687    
Liabilities subject to compromise     2,823,506    
Common stock 50 50 50    
Paid-in capital in excess of par     1,095,369    
Accumulated deficit 5,344 (50,658)      
Total stockholders' equity 1,135,390 1,053,668 1,095,419 $ 1,412,259 $ 1,141,777
Total liabilities and stockholders' equity $ 1,902,953 $ 1,634,758 1,751,407    
Predecessor          
Fresh-Start Adjustment [Line Items]          
Cash and cash equivalents     73,372    
Accrued production receivable     112,832    
Trade and other receivables, net     36,221    
Derivative assets     32,635    
Prepaids     12,968    
Total current assets     268,028    
Proved properties     11,723,546    
Unevaluated properties     650,553    
CO2 properties     1,198,515    
Pipelines     2,339,864    
Other property and equipment     201,565    
Less accumulated depletion, depreciation, amortization and impairment     (12,864,141)    
Net property and equipment     3,249,902    
Operating lease right-of-use assets     1,774    
Derivative assets     501    
Intangible assets, net     20,405    
Other assets     81,809    
Total assets     3,622,419    
Accounts payable and accrued liabilities     67,789    
Oil and gas production payable     39,372    
Derivative liabilities     8,613    
Total current liabilities     115,774    
Long-term debt     140,000    
Asset retirement obligations     2,727    
Derivative liabilities     295    
Total long-term liabilities not subject to compromise     143,022    
Liabilities subject to compromise     2,823,506    
Common stock     510    
Paid-in capital in excess of par     2,764,915    
Predecessor treasury stock, at cost     (6,202)    
Accumulated deficit     (2,219,106)    
Total stockholders' equity     540,117    
Total liabilities and stockholders' equity     3,622,419    
Reorganization Adjustments          
Fresh-Start Adjustment [Line Items]          
Cash and cash equivalents     (27,787)    
Restricted cash     10,662    
Prepaids     (539)    
Total current assets     (17,664)    
Other assets     8,241    
Total assets     (9,423)    
Accounts payable and accrued liabilities     102,793    
Oil and gas production payable     16,705    
Current maturities of long-term debt     73,199    
Operating lease liabilities     757    
Total current liabilities     193,454    
Long-term debt     42,610    
Asset retirement obligations     180,408    
Deferred tax liabilities, net     417,951    
Operating lease liabilities     515    
Other liabilities     3,540    
Total long-term liabilities not subject to compromise     645,024    
Liabilities subject to compromise     (2,823,506)    
Predecessor treasury stock, at cost     6,202    
Accumulated deficit     3,639,409    
Total stockholders' equity     1,975,605    
Total liabilities and stockholders' equity     (9,423)    
Reorganization Adjustments | Predecessor Adjustment          
Fresh-Start Adjustment [Line Items]          
Common stock     (510)    
Paid-in capital in excess of par     (2,764,915)    
Reorganization Adjustments | Successor Adjustment          
Fresh-Start Adjustment [Line Items]          
Common stock     50    
Paid-in capital in excess of par     1,095,369    
Fresh Start Adjustments          
Fresh-Start Adjustment [Line Items]          
Proved properties     (10,941,313)    
Unevaluated properties     (538,570)    
CO2 properties     (1,011,169)    
Pipelines     (2,207,246)    
Other property and equipment     (104,152)    
Less accumulated depletion, depreciation, amortization and impairment     12,864,141    
Net property and equipment     (1,938,309)    
Operating lease right-of-use assets     69    
Intangible assets, net     79,678    
Other assets     (3,027)    
Total assets     (1,861,589)    
Accounts payable and accrued liabilities     3,738    
Current maturities of long-term debt     364    
Operating lease liabilities     (29)    
Total current liabilities     4,073    
Long-term debt     (25,151)    
Asset retirement obligations     (24,697)    
Deferred tax liabilities, net     (414,120)    
Operating lease liabilities     10    
Other liabilities     18,599    
Total long-term liabilities not subject to compromise     (445,359)    
Accumulated deficit     (1,420,303)    
Total stockholders' equity     (1,420,303)    
Total liabilities and stockholders' equity     $ (1,861,589)    
v3.22.0.1
Fresh Start Accounting (Net Cash Payments) (Details 4)
$ in Thousands
9 Months Ended
Sep. 18, 2020
USD ($)
Reorganizations [Abstract]  
Cash proceeds from Successor Bank Credit Agreement $ 140,000
Total cash proceeds 140,000
Payment in full DIP Facility and pre-petition revolving bank credit agreement (140,000)
Retained professional service provider fees paid to escrow account (10,662)
Non-retained professional service provider fees paid (7,420)
Accrued interest and fees on DIP Facility (1,464)
Debt issuance costs related to Successor Bank Credit Agreement (8,241)
Total cash uses (167,787)
Net uses $ (27,787)
v3.22.0.1
Fresh Start Accounting (Accounts Payable and Accrued Liabilities) (Details 5) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Fresh-Start Adjustment [Line Items]      
Total $ 191,598 $ 112,671 $ 174,320
Accrual of professional service provider fees     2,826
Payment of accrued interest and fees on DIP Facility     (1,464)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise     101,431
Reorganization Adjustments      
Fresh-Start Adjustment [Line Items]      
Total     $ 102,793
v3.22.0.1
Fresh Start Accounting (Liabilities Subject to Compromise) (Details 6) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Reorganization Value [Line Items]      
Current maturities of long-term debt $ 0 $ 68,008 $ 73,563
Oil and gas production payable     56,077
Operating lease liabilities - current 4,677 1,350 728
Long-term debt, net of current portion 35,000 70,000 157,459
Asset retirement obligations 284,238 179,338 158,438
Operating lease liabilities - long-term 17,094 19,460 525
Other long-term liabilities $ 22,910 $ 20,872 22,139
Senior secured second lien notes     1,629,457
Convertible senior notes     234,015
Senior subordinated notes     251,480
Total settled liabilities subject to compromise     2,114,952
Accounts payable and accrued liabilities     101,431
Deferred tax liabilities     289,389
Total reinstated liabilities subject to compromise     708,554
Total liabilities subject to compromise     2,823,506
Issuance of New Common Stock to second lien note holders     (1,014,608)
Issuance of New Common Stock to convertible note holders     (53,400)
Issuance of series A warrants to convertible note holders     (15,683)
Issuance of series B warrants to senior subordinated note holders     (6,398)
Reinstatement of liabilities subject to compromise     (708,553)
Gain on settlement of liabilities subject to compromise     1,024,864
Reorganization Adjustments      
Reorganization Value [Line Items]      
Current maturities of long-term debt     73,199
Oil and gas production payable     16,705
Operating lease liabilities - current     757
Long-term debt, net of current portion     42,610
Asset retirement obligations     180,408
Operating lease liabilities - long-term     515
Other long-term liabilities     3,540
Total liabilities subject to compromise     $ (2,823,506)
v3.22.0.1
Fresh Start Accounting (Successor's Common Stock and Additional Paid-In Capital) (Details 7) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Reorganizations [Abstract]      
Capital in excess of par value of 47, 499,999 issued and outstanding shares of New Common Stock issued to holders of the senior secured second lien note claims     $ 1,014,608
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock issued to holders of the convertible senior note claims     53,400
Fair value of series A warrants issued to convertible senior note holders     15,683
Fair value of series B warrants issued to senior subordinated note holders     6,398
Fair value of series B warrants issued to Predecessor equity holders     5,330
Total change in Successor common stock and additional paid-in capital     1,095,419
Less: Par value of Successor common stock $ (50) $ (50) (50)
Change in Successor additional paid-in capital     $ 1,095,369
v3.22.0.1
Fresh Start Accounting (Accumulated Deficit Adjustments) (Details 8) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Fresh-Start Adjustment [Line Items]      
Accumulated deficit $ 5,344 $ (50,658)  
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock     $ 2,763,824
Gain on settlement of liabilities subject to compromise     1,024,864
Acceleration of Predecessor stock compensation expense     (4,601)
Recognition of tax expenses related to reorganization adjustments     (128,556)
Professional service provider fees recognized at emergence     (9,700)
Issuance of series B warrants to Predecessor equity holders     (5,330)
Other     (1,092)
Net impact to Predecessor accumulated deficit $ 5,344 $ (50,658)  
Reorganization Adjustments      
Fresh-Start Adjustment [Line Items]      
Accumulated deficit     3,639,409
Net impact to Predecessor accumulated deficit     $ 3,639,409
v3.22.0.1
Fresh Start Accounting (Fair Value Other Assets) (Details 9) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Fresh-Start Adjustment [Line Items]      
Fair value adjustments to other assets $ 78,298 $ 86,408 $ 87,023
Fair value adjustment for CO2 and oil pipeline line-fill     (3,698)
Fair value adjustments for escrow accounts     671
Fresh Start Adjustments      
Fresh-Start Adjustment [Line Items]      
Fair value adjustments to other assets     $ (3,027)
v3.22.0.1
Fresh Start Accounting (Fair Value Accounts Payable and Accrued Liabilities) (Details 10) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Fresh-Start Adjustment [Line Items]      
Total $ 191,598 $ 112,671 $ 174,320
Fair value adjustment for the current portion of an unfavorable vendor contract     3,500
Fair value adjustment for the current portion of Predecessor asset retirement obligation     689
Write-off accrued interest on NEJD pipeline financing     (451)
Fresh Start Adjustments      
Fresh-Start Adjustment [Line Items]      
Total     $ 3,738
v3.22.0.1
Fresh Start Accounting (Debt Adjustments) (Details 11)
$ in Thousands
Sep. 18, 2020
USD ($)
Reorganizations [Abstract]  
Fair value adjustment for Free State pipeline lease financing $ (24,699)
Fair value adjustment for NEJD pipeline lease financing (88)
Fair value adjustments to current and long-term maturities of debt $ (24,787)
v3.22.0.1
Fresh Start Accounting (Details Textuals) - USD ($)
$ / shares in Units, $ in Thousands
2 Months Ended 9 Months Ended
Sep. 18, 2020
Sep. 18, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2020
Reorganization Value [Line Items]          
Enterprise value $ 1,280,856 $ 1,280,856 $ 1,280,856    
Contractual interest expense on prepetition liabilities not recognized in statement of operations   22,000      
DIP credit agreement fees     3,107    
Capitalized costs of proved and unproved properties $ 865,400 865,400 865,400    
Expected annual dividend yield for warrants 0.00%        
Decrease to deferred taxes $ 128,600 128,600 128,600    
Deferred tax liabilities, net 3,831 3,831 3,831 $ 1,638 $ 1,274
Stockholders' Equity, Period Increase (Decrease) 4,600   (5,331)    
Fresh Start Adjustments          
Reorganization Value [Line Items]          
Deferred tax liabilities, net (414,120) (414,120) (414,120)    
Minimum          
Reorganization Value [Line Items]          
Enterprise value 1,100,000 1,100,000 1,100,000    
Maximum          
Reorganization Value [Line Items]          
Enterprise value 1,500,000 1,500,000 1,500,000    
Median          
Reorganization Value [Line Items]          
Enterprise value $ 1,300,000 $ 1,300,000 $ 1,300,000    
Series A Warrants          
Reorganization Value [Line Items]          
Exercise price of warrants $ 32.59 $ 32.59 $ 32.59 $ 32.59  
Expected volatility of warrants 49.30%        
Risk free interest rate associated with warrants 0.30%        
Term of warrants 5 years 5 years 5 years    
Series B Warrants          
Reorganization Value [Line Items]          
Exercise price of warrants $ 35.41 $ 35.41 $ 35.41 $ 35.41  
Expected volatility of warrants 53.60%        
Risk free interest rate associated with warrants 0.20%        
Term of warrants 3 years 3 years 3 years    
Measurement Input, Share Price          
Reorganization Value [Line Items]          
Implied stock price $ 22.14 $ 22.14 $ 22.14    
v3.22.0.1
Acquisition and Divestitures (Purchase Price Allocation) (Details) - Big Sand Draw and Beaver Creek Fields
$ in Thousands
Mar. 03, 2021
USD ($)
Business Acquisition [Line Items]  
Cash consideration $ 10,906
Proved oil and natural gas properties 60,101
Other property and equipment 1,685
Asset retirement obligations (39,794)
Contingent consideration (5,320)
Other liabilities (5,766)
Fair value of net assets acquired $ 10,906
v3.22.0.1
Acquisition and Divestitures (Details Textuals)
1 Months Ended 3 Months Ended 6 Months Ended 9 Months Ended 10 Months Ended 12 Months Ended
Jun. 30, 2021
USD ($)
Mar. 03, 2021
USD ($)
Sep. 18, 2020
$ / Barrel
Mar. 04, 2020
USD ($)
Jan. 31, 2022
USD ($)
Mar. 31, 2021
$ / Barrel
Dec. 31, 2020
USD ($)
Dec. 31, 2021
USD ($)
Sep. 18, 2020
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2021
USD ($)
$ / Barrel
Dec. 31, 2020
$ / Barrel
Dec. 31, 2019
USD ($)
$ / Barrel
Business Acquisition, Contingent Consideration [Line Items]                          
Average oil price | $ / Barrel     40.08     36.40         63.86 35.84 55.55
Approximate working interest percentage acquired   100.00%                      
Approximate net revenue interest percentage acquired   83.00%                      
Fair value of contingent consideration               $ 7,700,000   $ 7,700,000 $ 7,700,000    
Increase in contingent consideration                   $ 2,400,000      
Net proceeds from sales of oil and natural gas properties and equipment $ 18,000,000     $ 40,000,000     $ 938,000   $ 41,322,000   19,053,000   $ 10,196,000
Gain (loss) on disposition of oil and natural gas properties $ 0     $ 0                  
Gross proceeds from land sales               15,200,000          
Gain from asset sales and other             $ 3,546,000 $ 10,300,000 $ 6,723,000   $ 10,609,000   $ 8,504,000
Big Sand Draw and Beaver Creek Fields                          
Business Acquisition, Contingent Consideration [Line Items]                          
Cash consideration for acquisition of oil and natural gas properties   $ 10,906,000                      
Contingent consideration at acquisition date   5,320,000                      
Big Sand Draw and Beaver Creek Fields | Subsequent Event                          
Business Acquisition, Contingent Consideration [Line Items]                          
Contingency payment paid in January 2022         $ 4,000,000                
2021 | Big Sand Draw and Beaver Creek Fields                          
Business Acquisition, Contingent Consideration [Line Items]                          
Contingent cash payment   4,000,000                      
2021 | Minimum | Big Sand Draw and Beaver Creek Fields                          
Business Acquisition, Contingent Consideration [Line Items]                          
Average oil price | $ / Barrel                     50    
2022 | Big Sand Draw and Beaver Creek Fields                          
Business Acquisition, Contingent Consideration [Line Items]                          
Contingent cash payment   $ 4,000,000                      
2022 | Minimum | Big Sand Draw and Beaver Creek Fields                          
Business Acquisition, Contingent Consideration [Line Items]                          
Average oil price | $ / Barrel                     50    
v3.22.0.1
Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Disaggregation of Revenue        
Revenues $ 215,903 $ 521,693 $ 1,242,872 $ 1,260,360
Oil sales        
Disaggregation of Revenue        
Revenues 199,769 489,251 1,148,022 1,205,083
Natural gas sales        
Disaggregation of Revenue        
Revenues 1,339 2,850 11,933 6,937
CO2 sales and transportation fees        
Disaggregation of Revenue        
Revenues 9,419 21,049 44,175 34,142
Oil marketing revenues        
Disaggregation of Revenue        
Revenues $ 5,376 $ 8,543 $ 38,742 $ 14,198
v3.22.0.1
Leases (Supplemental Balance Sheet Information Related to Leases) (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Leases, Operating [Abstract]      
Operating lease right-of-use assets $ 19,502 $ 20,342 $ 1,843
Operating lease liabilities - current 4,677 1,350 728
Operating lease liabilities - long-term 17,094 19,460 $ 525
Total operating lease liabilities $ 21,771 $ 20,810  
v3.22.0.1
Leases (Lease Term and Discount Rate) (Details 1)
Dec. 31, 2021
Rate
Dec. 31, 2020
Rate
Leases [Abstract]    
Weighted average remaining lease term 5 years 2 months 12 days 6 years 3 months 18 days
Weighted average discount rate 5.40% 5.60%
v3.22.0.1
Leases (Lease Operating Costs) (Details 2) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Lease Cost [Line Items]        
Operating lease cost $ 1,044 $ 5,934 $ 4,807 $ 8,987
Lease cost        
Amortization of right-of-use assets 3 9 0 1,188
Interest on lease liabilities 1 3 0 40
Total finance lease cost 4 12 0 1,228
Variable lease cost 258 3,688 670 4,852
Sublease income 100 2,584 0 4,127
General and administrative expenses        
Lease Cost [Line Items]        
Operating lease cost 872 5,683 4,102 8,924
Lease operating expenses        
Lease Cost [Line Items]        
Operating lease cost 158 214 655 58
CO2 operating and discovery expenses        
Lease Cost [Line Items]        
Operating lease cost $ 14 $ 37 $ 50 $ 5
v3.22.0.1
Leases (Supplemental Cash Flow Information Related to Leases) (Details 3) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities        
Operating cash flows from operating leases $ 341 $ 7,341 $ 2,830 $ 10,995
Operating cash flows from interest on finance leases 1 3 0 40
Financing cash flows from finance leases 78 10 0 1,275
Right-of-use assets obtained in exchange for lease obligations        
Operating leases 19,902 1,049 2,683 415
Finance leases $ 0 $ 162 $ 0 $ 0
v3.22.0.1
Leases (Maturities of Lease Liabilities) (Details 4) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Leases [Abstract]      
2022 $ 5,705    
2023 4,712    
2024 4,138    
2025 4,177    
2026 4,203    
Thereafter 2,326    
Total minimum lease payments 25,261    
Less: Amount representing interest (3,490)    
Present value of minimum lease liabilities 21,771 $ 20,810  
Derivative Liability, Noncurrent $ 0 $ (5,087) $ (295)
v3.22.0.1
Leases (Details Textuals) - Maximum
Dec. 31, 2021
Lessee, Lease, Description [Line Items]  
Remaining lease term 14 years
Land  
Lessee, Lease, Description [Line Items]  
Remaining lease term 48 years
v3.22.0.1
Asset Retirement Obligations (Rollforward) (Details) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Asset Retirement Obligation Roll Forward [Roll Forward]      
Beginning asset retirement obligations $ 163,368 $ 181,760 $ 186,281
Liabilities incurred and assumed during period 738 736 43,701
Revisions in estimated retirement obligations 22,660 3,592 69,059
Liabilities settled and sold during period (3,439) (10,041) (10,783)
Accretion expense 2,954 11,329 14,353
Fresh start accounting adjustment 0 (24,008) 0
Ending asset retirement obligations 186,281 163,368 302,611
Less: current asset retirement obligations [1] (6,943) (4,930) (18,373)
Long-term asset retirement obligations $ 179,338 $ 158,438 $ 284,238
[1] Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.
v3.22.0.1
Asset Retirement Obligations (Details Textuals) - USD ($)
$ in Millions
Dec. 31, 2021
Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]    
Balance in escrow accounts $ 55.6 $ 55.2
v3.22.0.1
Unevaluated Property (Summary of Unevaluated Properties Excluded from Amortization) (Details) - USD ($)
$ in Thousands
3 Months Ended 12 Months Ended
Sep. 18, 2020
Dec. 31, 2020
Dec. 31, 2021
Summary of unevaluated properties excluded from oil and natural gas properties being amortized      
Property acquisition costs $ 68,103 [1] $ 0 $ 0
Exploration and development 0 46 39,481
Capitalized interest 0 963 3,576
Total 68,103 [1] 1,009 43,057
Property acquisition costs     68,103
Exploration and development     39,527
Capitalized interest     4,539
Total $ 111,983 $ 85,304 $ 112,169
[1] Reflects the carrying values of our unevaluated properties as a result of the application of fresh start accounting upon emergence from bankruptcy (see Note 2, Fresh Start Accounting, for additional information) that remain in unevaluated properties as of December 31, 2021.
v3.22.0.1
Unevaluated Property (Details Textuals)
12 Months Ended
Dec. 31, 2021
Maximum  
Capitalized Costs of Unproved Properties Excluded from Amortization  
Anticipated timing of inclusion of costs in amortization calculation 10 years
Minimum  
Capitalized Costs of Unproved Properties Excluded from Amortization  
Anticipated timing of inclusion of costs in amortization calculation 5 years
v3.22.0.1
Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Debt and Lease Obligation [Abstract]      
Senior Secured Bank Credit Agreement $ 35,000 $ 70,000  
Pipeline financings 0 68,008  
Total debt principal balance 35,000 138,008  
Less: current maturities of long-term debt 0 (68,008) $ (73,563)
Long-term debt $ 35,000 $ 70,000 $ 157,459
v3.22.0.1
Long-Term Debt (Debt Maturity Schedule) (Details 1)
$ in Thousands
Dec. 31, 2021
USD ($)
Indebtedness repayment schedule  
2022 $ 0
2023 0
2024 35,000
2025 0
2026 0
Thereafter 0
Total indebtedness $ 35,000
v3.22.0.1
Long-Term Debt (Details Textuals)
shares in Millions
1 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended
Oct. 30, 2020
USD ($)
Sep. 18, 2020
USD ($)
Mar. 31, 2020
USD ($)
Dec. 31, 2020
USD ($)
Jun. 30, 2020
USD ($)
shares
Sep. 18, 2020
USD ($)
Dec. 31, 2021
USD ($)
Dec. 31, 2019
USD ($)
Debt Instrument [Line Items]                
Interest in guarantor subsidiaries             100.00%  
Principal amount of debt cancelled   $ 2,100,000,000            
Lease period included in long-term transportation service agreement             20 years  
Shares issued upon conversion of notes | shares         7.4      
Debt principal balance net of debt discounts reclassified to equity         $ 13,900,000      
Cash paid for debt repurchases     $ 14,200,000 $ 0   $ 14,171,000 $ 0 $ 0
Gain on debt extinguishment     19,000,000 0   18,994,000 0 $ 155,998,000
Unamortized debt issuance costs       $ 8,400,000     5,700,000  
Senior Secured Bank Credit Facility [Abstract]                
Borrowing base             575,000,000  
Lender commitments   $ 575,000,000       $ 575,000,000 $ 575,000,000  
Percentage reduction of borrowing base upon issuing or incurring unsecured debt, expressed as a percentage of the principal amount of unsecured debt             25.00%  
Weighted average interest rate             4.00%  
Commitment fee percentage             0.50%  
Free State Pipeline                
Debt Instrument [Line Items]                
Payments to reacquire pipeline $ 22,500,000              
NEJD Pipeline                
Debt Instrument [Line Items]                
Payments to reacquire pipeline             $ 70,000,000  
Letter of Credit                
Senior Secured Bank Credit Facility [Abstract]                
Line of credit facility, capacity available for specific purpose other than for trade purchases             100,000,000  
Swingline Loan                
Senior Secured Bank Credit Facility [Abstract]                
Line of credit facility, capacity available for specific purpose other than for trade purchases             $ 25,000,000  
Minimum                
Senior Secured Bank Credit Facility [Abstract]                
Percentage threshold for borrowing base property sales or hedge terminations that would prompt a borrowing base reduction             5.00%  
Current ratio requirement             1.0  
Minimum | Dividend or Other Restricted Payment                
Senior Secured Bank Credit Facility [Abstract]                
Borrowing base availability requirement             20.00%  
Maximum                
Senior Secured Bank Credit Facility [Abstract]                
Consolidated total debt to consolidated EBITDAX requirement             3.5  
Maximum | Dividend or Other Restricted Payment                
Senior Secured Bank Credit Facility [Abstract]                
Consolidated total debt to consolidated EBITDAX requirement             2  
London Interbank Offered Rate (LIBOR)                
Senior Secured Bank Credit Facility [Abstract]                
Floor interest rate             1.00%  
London Interbank Offered Rate (LIBOR) | Minimum                
Senior Secured Bank Credit Facility [Abstract]                
Interest rate margins on senior secured bank credit facility             3.00%  
London Interbank Offered Rate (LIBOR) | Maximum                
Senior Secured Bank Credit Facility [Abstract]                
Interest rate margins on senior secured bank credit facility             4.00%  
Base Rate | Minimum                
Senior Secured Bank Credit Facility [Abstract]                
Interest rate margins on senior secured bank credit facility             2.00%  
Base Rate | Maximum                
Senior Secured Bank Credit Facility [Abstract]                
Interest rate margins on senior secured bank credit facility             3.00%  
9% Senior Secured Second Lien Notes due 2021                
Debt Instrument [Line Items]                
Debt repurchases, face amount     $ 30,200,000          
6 3/8% Convertible Senior Notes due 2024                
Debt Instrument [Line Items]                
Debt principal of notes converted         $ 19,900,000      
v3.22.0.1
Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Current income tax expense (benefit)        
Federal $ 0 $ (6,407) $ 0 $ 2,645
State 30 (853) 403 1,236
Total current income tax expense (benefit) 30 (7,260) 403 3,881
Deferred income tax expense (benefit)        
Federal 0 (319,011) 0 89,950
State (2,556) (89,858) 364 10,521
Total deferred income tax expense (benefit) (2,556) (408,869) 364 100,471
Total income tax expense (benefit) $ (2,526) $ (416,129) $ 767 $ 104,352
v3.22.0.1
Income Taxes (Summary of Changes in Valuation Allowance) (Details 1) - Tax Valuation Allowance - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Valuation Allowance [Line Items]        
Beginning balance $ 129,840 $ 77,215 $ 129,408 $ 51,093
Charges 2,269 77,138 29,345 26,122
Deductions (2,701) (24,513) (33,291) 0
Ending balance $ 129,408 $ 129,840 $ 125,462 $ 77,215
v3.22.0.1
Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 2) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Deferred tax assets    
Loss and tax credit carryforwards - state $ 54,943 $ 55,979
Derivative contracts 30,892 13,090
Accrued liabilities and other reserves 19,567 15,632
Business credit carryforwards 18,066 0
Loss carryforwards - federal 10,310 0
Lease liabilities 4,523 6,354
Property and equipment 2,613 59,207
Other 4,206 4,092
Valuation allowances (125,462) (129,408)
Total deferred tax assets 19,658 24,946
Deferred tax liabilities    
CO2 and other contracts (17,208) (20,030)
Operating lease right-of-use assets (4,088) (6,190)
Total deferred tax liabilities (21,296) (26,220)
Total net deferred tax liability $ (1,638) $ (1,274)
v3.22.0.1
Income Taxes (Schedule of Effective Tax Rate Reconciliation) (Details 3) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Amount        
Income tax provision calculated using the federal statutory income tax rate $ (11,169) $ (388,228) $ 11,921 $ 67,475
State income taxes, net of federal income tax benefit (2,532) (86,937) 450 7,435
Tax shortfall (windfall) on stock-based compensation deduction 0 (1,502) (267) 1,912
Nondeductible compensation 0 0 5,057 0
Change in valuation allowance 9,653 19,344 (2,928) 26,122
Enhanced oil recovery credits generated 0 0 (14,272) 0
Tax attributes reduction - net of CODI exclusion 0 31,667 0 0
Other 1,522 9,527 806 1,408
Total income tax expense (benefit) $ (2,526) $ (416,129) $ 767 $ 104,352
v3.22.0.1
Income Taxes (Details Textuals) - USD ($)
Dec. 31, 2021
Dec. 31, 2020
Valuation Allowance [Line Items]    
Federal net operating loss carryforwards $ 10,310,000 $ 0
Business credit carryforwards 18,066,000 0
Alternative minimum tax credits 600,000  
Loss and tax credit carryforwards - state 54,943,000 $ 55,979,000
Unrecognized tax benefits 0  
Income tax interest or penalties 0  
Louisiana, Mississippi, Montana, North Dakota and Alabama    
Valuation Allowance [Line Items]    
State deferred tax assets $ 74,100,000  
v3.22.0.1
Stockholders' Equity (Details Textuals) - 401(k) Plan - USD ($)
$ in Millions
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Defined Contribution Benefit Plans Disclosures [Line Items]        
Employer contribution rate     100.00%  
Employer's matching contributions $ 1.1 $ 4.4 $ 5.1 $ 6.3
Maximum        
Defined Contribution Benefit Plans Disclosures [Line Items]        
Employee contribution rate     6.00%  
v3.22.0.1
Stock Compensation (Schedule of Share-Based Compensation) (Details) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Abstract]        
Stock-based compensation expense included in G&A $ 8,212 $ 4,111 $ 25,322 $ 12,470
Stock-based compensation capitalized 695 1,660 1,883 4,018
Total cost of stock-based compensation arrangements 8,907 5,771 27,205 16,488
Income tax benefit recognized for stock-based compensation arrangements $ 2,053 $ 1,028 $ 6,331 $ 3,118
v3.22.0.1
Stock Compensation (Summary of Vesting Date Fair Value of RSU Awards) (Details 2)
$ in Thousands
12 Months Ended
Dec. 31, 2021
USD ($)
Restricted Stock Units  
Stock Compensation  
Vesting date fair value $ 31,073
v3.22.0.1
Stock Compensation (Summary of Restricted Stock Unit Activity) (Details 3) - Restricted Stock Units
12 Months Ended
Dec. 31, 2021
$ / shares
shares
Stock Compensation  
Nonvested at beginning of period | shares 1,219,867
Weighted average grant-date fair value, beginning of period | $ / shares $ 24.67
Granted | shares 56,236
Weighted average grant-date fair value, granted | $ / shares $ 31.87
Vested | shares (405,311)
Weighted average grant-date fair value, vested | $ / shares $ 24.80
Forfeited | shares (20,885)
Weighted average grant-date fair value, forfeited | $ / shares $ 24.67
Nonvested at end of period | shares 849,907
Weighted average grant-date fair value, end of period | $ / shares $ 25.08
v3.22.0.1
Stock Compensation (PSU Award Valuation Assumptions) (Details 4) - Performance Share Units - $ / shares
3 Months Ended 12 Months Ended
Dec. 31, 2020
Dec. 31, 2021
Stock Compensation    
Weighted average grant-date fair value, granted $ 24.19 $ 0
Risk-free interest rate 0.21%  
Expected life 2 months 23 days  
Expected volatility 110.00%  
Dividend yield 0.00%  
v3.22.0.1
Stock Compensation (Summary of PSU Activity) (Details 5) - Performance Share Units - $ / shares
3 Months Ended 12 Months Ended
Dec. 31, 2020
Dec. 31, 2021
Stock Compensation    
Nonvested at beginning of period   1,021,222
Weighted average grant-date fair value, beginning of period   $ 24.19
Granted   0
Weighted average grant-date fair value, granted $ 24.19 $ 0
Vested   (1,021,222)
Weighted average grant-date fair value, vested   $ 24.19
Forfeited   0
Weighted average grant-date fair value, forfeited   $ 0
Nonvested at end of period 1,021,222 0
Weighted average grant-date fair value, end of period $ 24.19 $ 0
v3.22.0.1
Stock Compensation (Summary of Vesting Date Fair Value of PSU Awards) (Details 6)
$ in Thousands
12 Months Ended
Dec. 31, 2021
USD ($)
Performance Share Units  
Stock Compensation  
Vesting date fair value $ 45,077
v3.22.0.1
Stock Compensation (Summary of Vesting Date Fair Value of Awards - Restricted Stock) (Details 7) - USD ($)
$ in Thousands
9 Months Ended 12 Months Ended
Sep. 18, 2020
Dec. 31, 2019
Restricted Stock    
Stock Compensation    
Fair value of restricted stock vested $ 707 $ 5,743
v3.22.0.1
Stock Compensation (TSR Award Assumptions) (Details 8) - Performance-Based TSR Awards - $ / shares
9 Months Ended 12 Months Ended
Sep. 18, 2020
Dec. 31, 2019
Stock Compensation    
Weighted average fair value of Performance-Based TSR Awards granted $ 0.15 $ 1.95
Risk-free interest rate 0.27% 2.27%
Expected life 3 years 3 years
Expected volatility 89.60% 77.20%
Dividend yield 0.00% 0.00%
v3.22.0.1
Stock Compensation (Summary of Vesting Date Fair Value of Awards) (Details 9) - USD ($)
$ in Thousands
9 Months Ended 12 Months Ended
Sep. 18, 2020
Dec. 31, 2019
Performance-Based Operational Awards    
Stock Compensation    
Vesting date fair value $ 0 $ 0
Performance-Based TSR Awards    
Stock Compensation    
Vesting date fair value $ 79 $ 2,783
v3.22.0.1
Stock Compensation (Details Textual)
1 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended
Dec. 04, 2020
shares
Jun. 30, 2020
USD ($)
Sep. 18, 2020
USD ($)
shares
Sep. 18, 2020
USD ($)
shares
Dec. 31, 2021
USD ($)
shares
Dec. 31, 2019
Stock Compensation            
Total executives and senior managers receiving cash retention incentive   21        
Total cash retention incentives paid to executive officers and senior managers   $ 15,200,000        
Repayment percentage   100.00%        
Unrecognized compensation expense   $ 18,700,000        
Incremental compensation expense   $ 4,100,000        
Acceleration of Predecessor stock compensation expense     $ 4,600,000 $ 4,601,000    
Percentage based on continued employment            
Stock Compensation            
Repayment percentage   50.00%        
Percentage based on metrics            
Stock Compensation            
Repayment percentage   50.00%        
Restricted Stock Units            
Stock Compensation            
Total grants | shares         56,236  
Award vesting or performance period         3 years  
Total compensation cost to be recognized in future periods         $ 19,900,000  
Weighted average period over which remaining cost will be recognized         1 year 10 months 24 days  
Performance Share Units            
Stock Compensation            
Total grants | shares         0  
Award vesting or performance period         3 years  
Total compensation cost to be recognized in future periods         $ 0  
Restricted Stock            
Stock Compensation            
Award vesting or performance period       3 years    
Total compensation cost to be recognized in future periods     0 $ 0    
Performance-based equity awards            
Stock Compensation            
Award vesting or performance period       3 years 3 months   3 years 3 months
Total compensation cost to be recognized in future periods     $ 0 $ 0    
2020 Omnibus Stock and Incentive Plan            
Stock Compensation            
Maximum number of common stock shares authorized for issuance under Plan | shares         6,200,000  
Total grants | shares 2,200,000          
Shares available for future awards | shares         3,900,000  
2004 Omnibus Stock and Incentive Plan            
Stock Compensation            
Maximum number of common stock shares authorized for issuance under Plan | shares     61,400,000 61,400,000    
v3.22.0.1
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - NYMEX
Dec. 31, 2021
bbl / d
$ / Barrel
Swap | Q1-Q2 2022  
Derivative [Line Items]  
Volume per day | bbl / d 15,500
Weighted average swap price 49.01
Swap | Q1-Q2 2022 | Minimum  
Derivative [Line Items]  
Derivative, Swap Type, Fixed Price 42.65
Swap | Q1-Q2 2022 | Maximum  
Derivative [Line Items]  
Derivative, Swap Type, Fixed Price 58.15
Swap | Q3 - Q4 2022 [Member]  
Derivative [Line Items]  
Volume per day | bbl / d 9,000
Weighted average swap price 56.35
Swap | Q3 - Q4 2022 [Member] | Minimum  
Derivative [Line Items]  
Derivative, Swap Type, Fixed Price 50.13
Swap | Q3 - Q4 2022 [Member] | Maximum  
Derivative [Line Items]  
Derivative, Swap Type, Fixed Price 60.35
Collar | Q1-Q2 2022  
Derivative [Line Items]  
Volume per day | bbl / d 11,000
Weighted average floor price 49.77
Weighted average ceiling price 64.31
Collar | Q1-Q2 2022 | Minimum  
Derivative [Line Items]  
Derivative, Floor Price 47.50
Collar | Q1-Q2 2022 | Maximum  
Derivative [Line Items]  
Derivative, Cap Price 70.75
Collar | Q3 - Q4 2022 [Member]  
Derivative [Line Items]  
Volume per day | bbl / d 10,000
Weighted average floor price 49.75
Weighted average ceiling price 64.18
Collar | Q3 - Q4 2022 [Member] | Minimum  
Derivative [Line Items]  
Derivative, Floor Price 47.50
Collar | Q3 - Q4 2022 [Member] | Maximum  
Derivative [Line Items]  
Derivative, Cap Price 70.75
v3.22.0.1
Fair Value Measurements (Fair Value Hierarchy) (Details) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis      
Oil derivative contracts - current assets $ 0 $ 187 $ 32,635
Total Assets   187  
Oil derivative contracts - current liabilities (134,509) (53,865) (8,613)
Oil derivative contracts - long-term liabilities 0 (5,087) $ (295)
Total Liabilities (134,509) (58,952)  
Quoted Prices in Active Markets (Level 1)      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis      
Oil derivative contracts - current assets   0  
Total Assets   0  
Oil derivative contracts - current liabilities 0 0  
Oil derivative contracts - long-term liabilities 0 0  
Total Liabilities 0 0  
Significant Other Observable Inputs (Level 2)      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis      
Oil derivative contracts - current assets   187  
Total Assets   187  
Oil derivative contracts - current liabilities (134,509) (53,865)  
Oil derivative contracts - long-term liabilities 0 (5,087)  
Total Liabilities (134,509) (58,952)  
Significant Unobservable Inputs (Level 3)      
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis      
Oil derivative contracts - current assets   0  
Total Assets   0  
Oil derivative contracts - current liabilities 0 0  
Oil derivative contracts - long-term liabilities 0 0  
Total Liabilities $ 0 $ 0  
v3.22.0.1
Fair Value Measurements (Details Textuals) - USD ($)
$ in Millions
Dec. 31, 2021
Dec. 31, 2020
Fair Value Disclosures [Abstract]    
Fair value of debt $ 35.0 $ 70.0
v3.22.0.1
Commitments and Contingencies (Details Textuals)
MMcf in Thousands
12 Months Ended
Dec. 31, 2021
USD ($)
$ / Barrel
MMcf
Commitments and Contingencies Disclosure [Abstract]  
Material tax assessments $ 0
Long-term Purchase Commitment [Line Items]  
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel 70
Industrial-sourced CO2 purchase contracts  
Long-term Purchase Commitment [Line Items]  
Term of long-term purchase commitments 7 years
Industrial CO2 customer contracts  
Long-term Purchase Commitment [Line Items]  
Significant supply commitment remaining volume committed (MMcf) | MMcf 572
Term of long-term supply arrangement 13 years
Processing fee related to overriding royalty interest in CO2 | Minimum  
Long-term Purchase Commitment [Line Items]  
Aggregate purchase obligation of CO2 $ 39,000,000
Processing fee related to overriding royalty interest in CO2 | Maximum  
Long-term Purchase Commitment [Line Items]  
Aggregate purchase obligation of CO2 $ 46,000,000
v3.22.0.1
Additional Balance Sheet Details (Details) - Trade and Other Receivables, Net - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Valuation Allowance [Line Items]        
Beginning balance $ 22,146 $ 17,137 $ 23,206 $ 17,070
Provision for doubtful accounts 1,060 5,297 826 68
Write-offs 0 (288) (5,085) (1)
Ending balance $ 23,206 $ 22,146 $ 18,947 $ 17,137
v3.22.0.1
Additional Balance Sheet Details (Details 2) - USD ($)
$ in Thousands
Dec. 31, 2021
Dec. 31, 2020
Sep. 18, 2020
Text Block [Abstract]      
Accrued lease operating expenses $ 27,901 $ 21,294  
Accrued derivative settlements 27,336 3,908  
Accounts payable 25,700 18,629  
Accrued compensation 23,735 7,512  
Accrued exploration and development costs 18,936 1,861  
Accrued asset retirement obligations - current 18,373 6,943  
Taxes payable 14,453 17,221  
Accrued general and administrative expenses 2,250 21,825  
Other 32,914 13,478  
Total $ 191,598 $ 112,671 $ 174,320
v3.22.0.1
Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
3 Months Ended 9 Months Ended 12 Months Ended
Dec. 31, 2020
Sep. 18, 2020
Dec. 31, 2021
Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]        
Cash paid for interest, expensed $ 813 $ 29,357 $ 4,227 $ 72,842
Cash paid for interest, capitalized 1,261 22,885 4,585 36,671
Cash paid for interest, treated as a reduction of debt 0 46,417 0 85,303
Cash paid for income taxes 0 453 184 2,361
Cash received from income tax refunds 10,457 1,932 3 9,820
Noncash investing and financing activities        
Increase in asset retirement obligations 23,398 4,328 112,760 13,560
Increase (decrease) in liabilities for capital expenditures 1,867 (12,809) 35,679 (17,740)
Conversion of convertible senior notes into common stock $ 0 $ 11,501 $ 0 $ 0