Denbury (DNRWW) 10-K 5 Mar 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Auditor Attestation Flag	true
Entity Shell Company	false
Entity Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 138,886,832
Entity Common Stock, Shares Outstanding		49,999,999
Documents Incorporated by Reference	1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 26, 2021.
Entity Central Index Key	0000945764
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 518,000	$ 516,000
Restricted cash	1,000,000	0
Accrued production receivable	91,421,000	139,407,000
Trade and other receivables, net	19,682,000	18,318,000
Derivative assets	187,000	11,936,000
Prepaids	14,038,000	10,434,000
Total current assets	126,846,000	180,611,000
Oil and natural gas properties (using full cost accounting)
Proved properties	851,208,000	11,447,680,000
Unevaluated properties	85,304,000	872,910,000
CO2 properties	188,288,000	1,198,846,000
Pipelines	133,485,000	2,329,078,000
Other property and equipment	86,610,000	212,334,000
Less accumulated depletion, depreciation, amortization and impairment	(41,095,000)	(11,688,020,000)
Net property and equipment	1,303,800,000	4,372,828,000
Operating lease right-of-use assets	20,342,000	34,099,000
Intangible asset, net	97,362,000	22,139,000
Other assets	86,408,000	82,190,000
Total assets	1,634,758,000	4,691,867,000
Current liabilities
Accounts payable and accrued liabilities	112,671,000	183,832,000
Oil and gas production payable	49,165,000	62,869,000
Derivative liabilities	53,865,000	8,346,000
Current maturities of long-term debt (including future interest payable of $0 and $86,054, respectively – see Note 8)	68,008,000	102,294,000
Operating lease liabilities	1,350,000	6,901,000
Total current liabilities	285,059,000	364,242,000
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 8)	70,000,000	2,232,570,000
Asset retirement obligations	179,338,000	177,108,000
Derivative liabilities	5,087,000	0
Deferred tax liabilities, net	1,274,000	410,230,000
Operating lease liabilities	19,460,000	41,932,000
Other liabilities	20,872,000	53,526,000
Total long-term liabilities	296,031,000	2,915,366,000
Commitments and contingencies (Note 14)
Stockholders' equity
Preferred stock, $.001 par value	0	0
Common stock, $.001 par value	50,000	508,000
Paid-in capital in excess of par	1,104,276,000	2,739,099,000
Predecessor treasury stock, at cost, 1,652,771 shares		(6,034,000)
Accumulated deficit	(50,658,000)	(1,321,314,000)
Total stockholders' equity	1,053,668,000	1,412,259,000
Total liabilities and stockholders' equity	$ 1,634,758,000	$ 4,691,867,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Stockholders' equity
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	50,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	250,000,000	750,000,000
Common stock, shares issued	49,999,999	508,065,495
Treasury stock, shares	0	1,652,771
Debt Instrument [Line Items]
Future interest payable - current	$ 68,008	$ 102,294
Future interest payable - long-term	70,000	2,232,570
Future interest payable on senior secured notes
Debt Instrument [Line Items]
Future interest payable - current	0	86,054
Future interest payable - long-term	$ 0	$ 78,860

Consolidated Statements of Oper

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, 2019	Dec. 31, 2018
Revenues and other income	$ 220,600,000	$ 530,112,000	$ 1,274,883,000	$ 1,473,625,000
Expenses
Taxes other than income	16,584,000	43,531,000	93,752,000	104,670,000
General and administrative expenses	19,470,000	48,522,000	83,029,000	71,495,000
Interest, net of amounts capitalized of $1,261, $22,885, $36,671 and $37,079, respectively	1,815,000	48,267,000	81,632,000	69,688,000
Depletion, depreciation, and amortization	45,812,000	188,593,000	233,816,000	216,449,000
Commodity derivatives expense (income)	61,902,000	(102,032,000)	70,078,000	(21,087,000)
Gain on debt extinguishment	0	(18,994,000)	(155,998,000)	0
Write-down of oil and natural gas properties	1,006,000	996,658,000	0	0
Reorganization items, net	0	849,980,000	0	0
Other expenses	8,072,000	35,868,000	11,187,000	84,325,000
Total expenses	273,784,000	2,378,819,000	953,572,000	1,063,694,000
Income (loss) before income taxes	(53,184,000)	(1,848,707,000)	321,311,000	409,931,000
Income tax provision (benefit)	(2,526,000)	(416,129,000)	104,352,000	87,233,000
Net income (loss)	$ (50,658,000)	$ (1,432,578,000)	$ 216,959,000	$ 322,698,000
Net income (loss) per common share
Basic	$ (1.01)	$ (2.89)	$ 0.47	$ 0.75
Diluted	$ (1.01)	$ (2.89)	$ 0.45	$ 0.71
Weighted average common shares outstanding
Basic	50,000	495,560	459,524	432,483
Diluted	50,000	495,560	510,341	456,169
Other income
Revenues and other income	$ 4,697,000	$ 8,419,000	$ 14,523,000	$ 17,970,000
Transportation and marketing
Operating expenses	10,595,000	27,164,000	41,810,000	43,942,000
Oil, natural gas, and related product sales
Revenues and other income	201,108,000	492,101,000	1,212,020,000	1,422,589,000
Operating expenses	101,234,000	250,271,000	477,220,000	489,720,000
CO2
Revenues and other income	9,419,000	21,049,000	34,142,000	31,145,000
Operating expenses	1,976,000	2,592,000	2,922,000	2,816,000
Oil marketing
Revenues and other income	5,376,000	8,543,000	14,198,000	1,921,000
Operating expenses	$ 5,318,000	$ 8,399,000	$ 14,124,000	$ 1,676,000

Consolidated Statements of Op_2

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, 2019	Dec. 31, 2018
Expenses
Capitalized interest	$ 1,261	$ 22,885	$ 36,671	$ 37,079

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net income (loss)	$ (50,658,000)	$ (1,432,578,000)	$ 216,959,000	$ 322,698,000
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	233,816,000	216,449,000
Write-down of oil and natural gas properties	1,006,000	996,658,000	0	0
Deferred income taxes	(2,556,000)	(408,869,000)	100,471,000	103,234,000
Stock-based compensation	8,212,000	4,111,000	12,470,000	11,951,000
Commodity derivatives expense (income)	61,902,000	(102,032,000)	70,078,000	(21,087,000)
Receipt (payment) on settlements of commodity derivatives	21,089,000	81,396,000	23,606,000	(175,248,000)
Gain on debt extinguishment	0	(18,994,000)	(155,998,000)	0
Debt issuance costs and discounts	799,000	11,571,000	12,303,000	6,246,000
Other, net	(2,349,000)	439,000	(8,596,000)	(4,725,000)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	21,411,000	26,575,000	(13,619,000)	20,547,000
Trade and other receivables	15,567,000	(22,343,000)	9,379,000	16,094,000
Other current and long-term assets	(1,795,000)	743,000	7,629,000	(6,827,000)
Accounts payable and accrued liabilities	(67,167,000)	(16,102,000)	(3,275,000)	13,008,000
Oil and natural gas production payable	(6,912,000)	(6,792,000)	2,170,000	(15,300,000)
Other liabilities	(4,035,000)	123,000	(13,250,000)	42,645,000
Net cash provided by operating activities	40,326,000	113,408,000	494,143,000	529,685,000
Cash flows from investing activities
Oil and natural gas capital expenditures	(17,964,000)	(99,582,000)	(262,005,000)	(316,647,000)
CO2 capital expenditures	(269,000)	(196,000)	(3,154,000)	(5,878,000)
Pipelines and plants capital expenditures	(618,000)	(11,601,000)	(27,319,000)	(23,108,000)
Net proceeds from sales of oil and natural gas properties and equipment	938,000	41,322,000	10,196,000	7,762,000
Other	16,029,000	12,943,000	12,590,000	4,595,000
Net cash used in investing activities	(1,884,000)	(57,114,000)	(269,692,000)	(333,276,000)
Cash flows from financing activities
Bank repayments	(190,000,000)	(551,000,000)	(925,791,000)	(1,982,653,000)
Bank borrowings	120,000,000	691,000,000	925,791,000	1,507,653,000
Interest payments treated as a reduction of debt	0	(46,417,000)	(85,303,000)	(79,606,000)
Proceeds from issuance of senior secured notes	0	0	0	450,000,000
Cash paid in conjunction with debt exchange	0	0	(136,427,000)	0
Cash paid in conjunction with debt repurchases	0	(14,171,000)	0	0
Costs of debt financing	(8,000)	(12,482,000)	(11,065,000)	(16,060,000)
Pipeline financing and capital lease debt repayments	(22,938,000)	(51,792,000)	(13,908,000)	(23,300,000)
Other	1,638,000	(9,363,000)	348,000	(13,486,000)
Net cash provided by (used in) financing activities	(91,308,000)	5,775,000	(246,355,000)	(157,452,000)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(52,866,000)	62,069,000	(21,904,000)	38,957,000
Cash, cash equivalents, and restricted cash at beginning of period	95,114,000	33,045,000	54,949,000	15,992,000
Cash, cash equivalents, and restricted cash at end of period	$ 42,248,000	$ 95,114,000	$ 33,045,000	$ 54,949,000

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($)	Total	Common Stock ($.001 Par Value)	Paid-In Capital in Excess of Par	Retained Earnings (Accumulated Deficit)	Treasury Stock (at cost)
Beginning balance, shares at Dec. 31, 2017		402,549,346			457,041
Beginning balance at Dec. 31, 2017	$ 648,165,000	$ 403,000	$ 2,507,828,000	$ (1,855,810,000)	$ (4,256,000)
Issued pursuant to stock compensation plans, shares		4,556,424
Issued pursuant to stock compensation plans, value		$ 4,000	(4,000)
Issued pursuant to notes conversion, shares		55,249,955
Issued pursuant to notes conversion, value	162,004,000	$ 55,000	161,949,000
Stock-based compensation, value	15,438,000		15,438,000
Tax withholding for stock compensation plans, shares					1,484,708
Tax withholding for stock compensation plans, value	(6,528,000)				$ (6,528,000)
Net income (loss)	322,698,000			322,698,000
Ending balance, shares at Dec. 31, 2018		462,355,725			1,941,749
Ending balance at Dec. 31, 2018	1,141,777,000	$ 462,000	2,685,211,000	(1,533,112,000)	$ (10,784,000)
Issued pursuant to stock compensation plans, shares		9,315,016
Issued pursuant to stock compensation plans, value		$ 9,000	(9,000)
Issued pursuant to notes conversion, value	0
Stock-based compensation, value	16,488,000		16,488,000
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	39,555,000	$ 37,000	37,409,000	(5,161,000)	$ 7,270,000
Tax withholding for stock compensation plans, shares					1,701,022
Tax withholding for stock compensation plans, value	(2,520,000)				$ (2,520,000)
Net income (loss)	$ 216,959,000			216,959,000
Ending balance, shares at Dec. 31, 2019	508,065,495	508,065,495			1,652,771
Ending balance at Dec. 31, 2019	$ 1,412,259,000	$ 508,000	2,739,099,000	(1,321,314,000)	$ (6,034,000)
Issued pursuant to stock compensation plans, shares		312,516
Issued pursuant to notes conversion, shares		7,372,250
Issued pursuant to notes conversion, value	11,501,000	$ 8,000	11,493,000
Stock-based compensation, value	14,317,000		14,317,000
Issued pursuant to directors' compensation plan, shares		37,367
Issuance of new shares, shares		49,999,999
Issuance of new shares, value	1,095,419,000	$ 50,000	1,095,369,000
Canceled pursuant to stock compensation plans, shares		(6,313,884)
Canceled pursuant to stock compensation plans, value	0	$ (6,000)	6,000
Tax withholding for stock compensation plans, shares					742,862
Tax withholding for stock compensation plans, value	(168,000)				$ (168,000)
Cancellation of Predecessor equity, shares		(509,473,744)			(2,395,633)
Cancellation of Predecessor equity, value	(5,331,000)	$ (510,000)	(2,764,915,000)	2,753,892,000	$ 6,202,000
Net income (loss)	(1,432,578,000)			(1,432,578,000)
Ending balance, shares at Sep. 18, 2020		49,999,999			0
Ending balance at Sep. 18, 2020	1,095,419,000	$ 50,000	1,095,369,000	0	$ 0
Issued pursuant to notes conversion, value	0
Stock-based compensation, value	8,907,000		8,907,000
Net income (loss)	$ (50,658,000)			(50,658,000)
Ending balance, shares at Dec. 31, 2020	49,999,999	49,999,999			0
Ending balance at Dec. 31, 2020	$ 1,053,668,000	$ 50,000	$ 1,104,276,000	$ (50,658,000)	$ 0

Nature of Operations and Summar

Nature of Operations and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
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 on producing oil from mature oil fields in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO 2 EOR and the emerging CCUS industry, supported by the Company’s CO 2 EOR technical and operational expertise and its extensive CO 2 pipeline infrastructure. The utilization of captured industrial-sourced CO 2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO 2 emissions within the decade. 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 (the “RSA”) 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 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 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 Debt – Restructuring 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. During the Chapter 11 Restructuring, the Company’s ability to continue as a going concern was contingent upon the Company’s ability to successfully implement a prepackaged joint plan of reorganization, among other factors. As a result of the effectiveness and implementation of the restructuring, there is no longer substantial doubt about the Company's ability to continue as a going concern. 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 CO 2 reserves used to compute depletion of CO 2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; (8) estimates made in the calculation of income taxes; and (9) 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 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, 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 Predecessor In thousands December 31, 2020 December 31, 2019 Cash and cash equivalents $ 518 $ 516 Restricted cash, current 1,000 — Restricted cash included in other assets 40,730 32,529 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 42,248 $ 33,045 Restricted cash, current in the table above represents restricted escrow funds related to a deposit for our Wyoming working interest acquisition (see Note 17, Subsequent Event ) and our December 2020 sale of non-producing surface acreage in the Houston area. Other restricted cash amounts represent 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 and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $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 (“COVID-19”) 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 CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $55.55 at December 31, 2019, $40.08 at September 18, 2020, and $35.84 at December 31, 2020. Primarily as a result of these commodity price declines, 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 Predecessor periods of 2018 or 2019. 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 CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs until we are able to recognize proved reserves associated with the development project. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs are expensed as incurred, and any previously deferred unevaluated development costs become subject to depletion. CO 2 Properties We own and produce CO 2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO 2 to third parties when it is produced and sold. Expenses related to the production of CO 2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO 2 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 CO 2 (see Tertiary Injection Costs above for further discussion). Costs incurred to search for CO 2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO 2 properties” on our Consolidated Balance Sheets. Capitalized CO 2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. Pipelines CO 2 used in our tertiary floods is transported to our fields through CO 2 pipelines. Costs of CO 2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 43 years. Capitalized costs include $0.7 million of CO 2 pipelines as of December 31, 2020, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2020. 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 and furniture and fixtures are generally depreciated over a useful life of one one 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 for the Predecessor period primarily consisted of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming, and for the Successor period represent amounts assigned in fresh start accounting to long-term contracts to sell CO 2 to industrial customers. We amortize the CO 2 contract intangible assets on a straight-line basis over their estimated useful lives, which range from seven Successor Predecessor In thousands December 31, 2020 December 31, 2019 Long-term contracts to sell CO 2 to industrial customers $ 97,943 $ — Other intangibles 2,167 37,668 Accumulated amortization (2,748) (15,529) Net book value $ 97,362 $ 22,139 As of December 31, 2020, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2021 $ 9,117 2022 9,117 2023 9,117 2024 9,117 2025 9,117 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 CO 2 properties and pipelines, and for the Successor period also included long-term contracts to sell CO 2 to industrial customers. Given the significant declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region) as of March 31, 2020 (Predecessor). 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 CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020 (Predecessor). 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. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and no impairment was recorded. Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO 2 , projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and September 18, 2020 (Predecessor periods) and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, no impairment test was performed for the second quarter of 2020 or for the period ending September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our long-lived assets being recorded at their fair value at the Emergence Date (see Note 2, Fresh Start Accounting , for additional information). We performed a qualitative assessment as of December 31, 2020 (Successor period) and determined there were no material changes to our key cash flow assumptions and no triggering events since the Company’s assets were revalued in fresh start accounting, September 18, 2020; therefore, no impairment test was performed for the fourth quarter of 2020. Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO 2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool. 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 Successor period September 19, 2020 through December 31, 2020, three purchasers 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 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 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%). For the year ended December 31, 2018 (Predecessor), two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply Company (10%). Other Receivables During 2018, we recorded a $16.9 million impairment of a loan related to a proposed plant in the Gulf Coast that would potentially supply CO 2 to Denbury, due to uncertainties of the project achieving financial close. The impairment was included within “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018. 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 bene

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2020
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 thousands Sept. 18, 2020 Enterprise value $ 1,280,856 Plus: Cash and cash equivalents 45,585 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 thousands Sept. 18, 2020 Enterprise value $ 1,280,856 Plus: Cash and cash equivalents 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 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 represent (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 and are recorded in “Reorganization items, net” in our Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred 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 In thousands 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 4,601 Total reorganization items, net $ 849,980 Payments of professional service provider fees and success fees of $12.7 million and fees of $3.1 million related to the Senior Secured Superpriority Debtor-in-Possession Credit Agreement (“DIP Facility”) were included in cash outflows from operating activities and financing activities, respectively, in our Consolidated Statements of Cash Flows for the period January 1, 2020 through September 18, 2020. Valuation Process The fair values of our principal assets, including oil and natural gas properties, CO 2 properties, pipelines, other property and equipment, long-term contracts to sell CO 2 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 Policies – Oil 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 CO 2 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). CO 2 Properties The fair value of CO 2 properties includes the value of CO 2 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 CO 2 as provided 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 CO 2 costs, since Denbury charges oil fields for CO 2 use on a cost basis. Cash flows were then discounted using a rate considering reduced risk associated with CO 2 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 provided 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, which will be depreciated on a straight-line basis ranging from 20 to 43 years. 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 CO 2 to Industrial Customers The fair value of long-term contracts to sell CO 2 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. The contracts will be depreciated over a useful life of seven 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 Debt – Restructuring 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-Merton model. The Black-Scholes-Merton 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 three 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 thousands Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Assets Current assets Cash and cash equivalents $ 73,372 $ (27,787) (1) $ — $ 45,585 Restricted cash — 10,662 (2) — 10,662 Accrued production receivable 112,832 — — 112,832 Trade and other receivables, net 36,221 — — 36,221 Derivative assets 32,635 — — 32,635 Other current assets 12,968 (539) (3) — 12,429 Total current assets 268,028 (17,664) — 250,364 Property and equipment Oil and natural gas properties (using full cost accounting) Proved properties 11,723,546 — (10,941,313) 782,233 Unevaluated properties 650,553 — (538,570) 111,983 CO 2 properties 1,198,515 — (1,011,169) 187,346 Pipelines 2,339,864 — (2,207,246) 132,618 Other property and equipment 201,565 — (104,152) 97,413 Less accumulated depletion, depreciation, amortization and impairment (12,864,141) — 12,864,141 — Net property and equipment 3,249,902 — (1,938,309) (10) 1,311,593 Operating lease right-of-use assets 1,774 — 69 (10) 1,843 Derivative assets 501 — — 501 Intangible assets, net 20,405 — 79,678 (11) 100,083 Other assets 81,809 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 thousands Predecessor Reorganization Adjustments Fresh Start Adjustments Successor 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 payable 39,372 16,705 (6) — 56,077 Derivative liabilities 8,613 — — 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 liabilities 115,774 193,454 4,073 313,301 Long-term liabilities Long-term debt, net of current portion 140,000 42,610 (6) (25,151) (14) 157,459 Asset retirement obligations 2,727 180,408 (6) (24,697) (10) 158,438 Derivative liabilities 295 — — 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 compromise 143,022 645,024 (445,359) 342,687 Liabilities subject to compromise 2,823,506 (2,823,506) (6) — — Commitments and contingencies (Note 14) Stockholders’ equity Predecessor preferred stock — — — — Predecessor common stock 510 (510) (7) — — Predecessor paid-in capital in excess of par 2,764,915 (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 proceeds 140,000 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 compromise 101,431 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 notes 234,015 Senior subordinated notes 251,480 Total settled liabilities subject to compromise 2,114,952 Reinstated liabilities subject to compromise Current maturities of long-term debt 73,199 Accounts payable and accrued liabilities 101,431 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 Deferred tax liabilities 289,389 Operating lease liabilities, long-term 515 Other long-term liabilities 3,540 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 (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 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) 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 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 $ 3,639,409 Fresh Start Adjustments (10) Reflects fair value adjustments to our (i) oil and natural gas properties, CO 2 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 CO 2 to industrial customers. (12) Reflects fair value adjustments to our other assets as follows: In thousands Fair value adjustment for CO 2 and oil pipeline line-fill $ (3,698) Fair value adjustments for escrow accounts 671 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 obligation 689 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 Debt – Restructuring 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.

Predecessor Divestiture

Predecessor Divestiture	12 Months Ended
	Dec. 31, 2020
Text Block [Abstract]
Predecessor Divestiture	Note 3. Predecessor Divestiture 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.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2020
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 CO 2 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 the risks and rewards of ownership (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 CO 2 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 CO 2 contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made 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 CO 2 sales and transportation contracts, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as 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: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Oil sales $ 199,769 $ 489,251 $ 1,205,083 $ 1,412,358 Natural gas sales 1,339 2,850 6,937 10,231 CO 2 sales and transportation fees 9,419 21,049 34,142 31,145 Oil marketing revenues 5,376 8,543 14,198 1,921 Total revenues $ 215,903 $ 521,693 $ 1,260,360 $ 1,455,655

Leases

Leases	12 Months Ended
	Dec. 31, 2020
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 7 years, with certain land leases having remaining terms up to 49 years. Leases with a term of 12 months or less are not recorded on our balance sheet. As part of the Chapter 11 Restructuring, the Predecessor elected to terminate some of its operating and finance leases, primarily related to office space. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our office leases: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Operating leases Operating lease right-of-use assets $ 20,342 $ 34,099 Operating lease liabilities – current $ 1,350 $ 6,901 Operating lease liabilities – long-term 19,460 41,932 Total operating lease liabilities $ 20,810 $ 48,833 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 Predecessor December 31, 2020 December 31, 2019 Weighted average remaining lease term 6.3 years 5.7 years Weighted average discount rate 5.6 % 6.7 % 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. 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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Income Statement Dec. 31, 2019 Operating lease cost General and administrative expenses $ 872 $ 5,683 $ 8,924 Lease operating expenses 158 214 58 CO 2 operating and discovery expenses 14 37 5 $ 1,044 $ 5,934 $ 8,987 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ 3 $ 9 $ 1,188 Interest on lease liabilities Interest expense 1 3 40 Total finance lease cost $ 4 $ 12 $ 1,228 Sublease income General and administrative expenses $ 100 $ 2,584 $ 4,127 Our statement of cash flows included the following activity related to our operating and finance leases: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 341 $ 7,341 $ 10,995 Operating cash flows from interest on finance leases 1 3 40 Financing cash flows from finance leases 78 10 1,275 Right-of-use assets obtained in exchange for lease obligations Operating leases 19,902 1,049 415 Finance leases — 162 — The following table summarizes by year the maturities of our lease liabilities as of December 31, 2020: Operating In thousands Leases 2021 $ 2,496 2022 4,149 2023 4,135 2024 4,111 2025 4,149 Thereafter 6,263 Total minimum lease payments 25,303 Less: Amount representing interest (4,493) Present value of minimum lease liabilities $ 20,810

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The following table summarizes the changes in our asset retirement obligations: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Beginning asset retirement obligations $ 163,368 $ 181,760 $ 176,585 Liabilities incurred and assumed during period 738 736 4,354 Revisions in estimated retirement obligations 22,660 3,592 9,206 Liabilities settled and sold during period (3,439) (10,041) (24,342) Accretion expense 2,954 11,329 15,957 Fresh start accounting adjustment — (24,008) — Ending asset retirement obligations 186,281 163,368 181,760 Less: current asset retirement obligations (1) (6,943) (4,930) (4,652) Long-term asset retirement obligations $ 179,338 $ 158,438 $ 177,108 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. Liabilities assumed relate to minor acquisitions, with liabilities incurred generally relating to wells and facilities. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $55.2 million and $53.4 million as of December 31, 2020 and 2019, 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, 2020 and 2019.

Unevaluated Property

Unevaluated Property	12 Months Ended
	Dec. 31, 2020
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, 2020, and the year in which the costs were incurred follows: December 31, 2020 Costs Incurred During: In thousands Successor 2020 Fresh Start Adjustments (Sept. 18, 2020) (1) Total Property acquisition costs $ — $ 84,019 $ 84,019 Exploration and development 46 — 46 Capitalized interest 1,239 — 1,239 Total $ 1,285 $ 84,019 $ 85,304 (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, 2020. 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 CO 2 tertiary potential at Tinsley, Oyster Bayou and Salt Creek fields. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil field projects that are under development but did not have associated proved reserves at December 31, 2020. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at lea st annually. We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten years . Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Note 8. Long-Term Debt The table below reflects long-term debt outstanding as of December 31, 2020 and 2019: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Successor Senior Secured Bank Credit Agreement $ 70,000 $ — Predecessor Senior Secured Bank Credit Agreement — — 9% Senior Secured Second Lien Notes due 2021 — 614,919 9¼% Senior Secured Second Lien Notes due 2022 — 455,668 7¾% Senior Secured Second Lien Notes due 2024 — 531,821 7½% Senior Secured Second Lien Notes due 2024 — 20,641 6⅜% Convertible Senior Notes due 2024 — 245,548 6⅜% Senior Subordinated Notes due 2021 — 51,304 5½% Senior Subordinated Notes due 2022 — 58,426 4⅝% Senior Subordinated Notes due 2023 — 135,960 Pipeline financings 68,008 167,439 Total debt principal balance 138,008 2,281,726 Debt discount — (101,767) Future interest payable — 164,914 Debt issuance costs — (10,009) Total debt, net of debt issuance costs and discount 138,008 2,334,864 Less: current maturities of long-term debt (68,008) (102,294) Long-term debt and capital lease obligations $ 70,000 $ 2,232,570 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 Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code , for additional information. Successor 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”). 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, 2021. 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 prohibits us from paying dividends on our common stock through September 17, 2021. Commencing on September 18, 2021, we may 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 at least 1.0 times. 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 ABR Loans, a base rate determined under the Successor Bank Credit Agreement (the “ABR”) 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, 2020 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, 2020, 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. On August 7, 2020, Genesis, as the beneficiary of the $41.3 million letter of credit issued as financial assurances under the NEJD pipeline lease financing, drew the full amount of such letter of credit in accordance with its terms as a result of the Predecessor’s Chapter 11 Restructuring, which resulted in a corresponding reduction to the principal balance outstanding under such financing. In late October 2020, we restructured our CO 2 pipeline financing arrangements with Genesis, whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million to be 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 (the “7¾% Senior Secured Notes”), 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”), 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Notes”), 6⅜% Senior Subordinated Notes due 2021 (the “Subordinated 2021 Notes”), 5½% Senior Subordinated Notes due 2022 (the “Subordinated 2022 Notes”), and 4⅝% Senior Subordinated Notes due 2023 (the “Subordinated 2023 Notes”) 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 During the third quarter of 2019, the Predecessor repurchased $11.0 million in aggregate principal amount of its then outstanding Subordinated 2022 Notes in open market transactions for a total purchase price of $5.3 million, excluding accrued interest. Additionally, during the fourth quarter of 2019, the Predecessor repurchased principally through exchanges an additional $25.3 million in aggregate principal amount of its then outstanding Subordinated 2022 Notes and $75.7 million in aggregate principal amount of its then outstanding Subordinated 2023 Notes for $11.2 million in cash and issuance of 38.3 million shares of the Predecessor’s common stock. In connection with these transactions, the Predecessor recognized a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2019, in its Consolidated Statements of Operations. During June 2019, in a series of debt exchanges, the Predecessor extended the maturities of its outstanding long-term debt and reduced the amount of outstanding debt principal. As part of these transactions, holders exchanged a total of $468.4 million aggregate principal amount of the Predecessor’s then outstanding senior subordinated notes for $102.6 million aggregate principal amount of 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of 2024 Convertible Notes and $120.0 million of cash. The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of Subordinated 2021 Notes, $219.9 million aggregate principal amount of Subordinated 2022 Notes and $96.3 million aggregate principal amount of Subordinated 2023 Notes. In addition, holders also exchanged $425.4 million of 7½% Senior Secured Notes for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes. In July 2019, holders exchanged an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. As a result, the Predecessor recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended December 31, 2019, in its Consolidated Statements of Operations. In accordance with FASC 470-50, Modifications and Extinguishments , the June 2019 exchange of the Predecessor’s existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, the 7¾% Senior Secured Notes and 2024 Convertible Notes were recorded on the balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively. Separately, the June 2019 exchange of the Predecessor’s existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the 7¾% Senior Secured Notes. 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 $8.4 million and $14.0 million at December 31, 2020 (Successor) and 2019 (Predecessor), respectively. Issuance costs associated with our Successor Bank Credit Agreement (Successor period) and Predecessor Bank Credit Agreement (Predecessor period) are included in “Other assets” in the Consolidated Balance Sheets, and issuance costs associated with the Predecessor’s senior secured second lien notes, convertible senior notes, and senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in the Consolidated Balance Sheets for the Predecessor period. Indebtedness Repayment Schedule At December 31, 2020, our indebtedness is payable over the next five years and thereafter as follows: In thousands 2021 $ 68,008 2022 — 2023 — 2024 70,000 2025 — Thereafter — Total indebtedness $ 138,008

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Note 9. Income Taxes Our income tax provision (benefit) is as follows: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Current income tax expense (benefit) Federal $ — $ (6,407) $ 2,645 $ (17,885) State 30 (853) 1,236 1,884 Total current income tax expense (benefit) 30 (7,260) 3,881 (16,001) Deferred income tax expense (benefit) Federal — (319,011) 89,950 93,395 State (2,556) (89,858) 10,521 9,839 Total deferred income tax expense (benefit) (2,556) (408,869) 100,471 103,234 Total income tax expense (benefit) $ (2,526) $ (416,129) $ 104,352 $ 87,233 At December 31, 2020, we had no federal net operating loss carryforwards (“NOLs”), tax effected business interest expense carryforward, or tax credits, as the Company’s federal tax attributes 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, 2020, 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 2021, and are recorded as a receivable on the balance sheet, and state NOLs and tax credits totaling $56.0 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, 2020 and 2019 balance sheet dates. As of December 31, 2020, we had $75.1 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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Dec. 31, 2018 Beginning balance $ 129,840 $ 77,215 $ 51,093 $ 51,134 Charges 2,269 77,138 26,122 — Deductions (2,701) (24,513) — (41) Ending balance $ 129,408 $ 129,840 $ 77,215 $ 51,093 As of December 31, 2020, 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, 2020 and 2019 are as follows: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Deferred tax assets Property and equipment $ 59,207 $ — Loss and tax credit carryforwards – state 55,979 52,917 Accrued liabilities and other reserves 15,632 29,788 Derivative contracts 13,090 — Lease liabilities 6,354 10,841 Business interest expense carryforward — 24,513 Business credit carryforwards — 71,555 Unrecognized gain and original issue discount on debt exchange — 41,556 Other 4,092 15,664 Valuation allowances (129,408) (77,215) Total deferred tax assets 24,946 169,619 Deferred tax liabilities CO 2 and other contracts (20,030) — Operating lease right-of-use assets (6,190) (7,780) Property and equipment — (569,254) Derivative contracts — (1,120) Other — (1,695) Total deferred tax liabilities (26,220) (579,849) Total net deferred tax liability $ (1,274) $ (410,230) 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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Income tax provision calculated using the federal statutory income tax rate $ (11,169) $ (388,228) $ 67,475 $ 86,086 State income taxes, net of federal income tax benefit (2,532) (86,937) 7,435 11,968 Tax shortfall (windfall) on stock-based compensation deduction — (1,502) 1,912 (1,565) Valuation allowance 9,653 19,344 26,122 (42) Tax attributes reduction – net of CODI exclusion — 31,667 — — Enhanced oil recovery tax credits generated — — — (10,818) Other 1,522 9,527 1,408 1,604 Total income tax expense (benefit) $ (2,526) $ (416,129) $ 104,352 $ 87,233 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 2017 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.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Note 10. Stockholders’ Equity Registration Rights Agreement On the Emergence Date, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain former beneficial holders of the second lien notes of the Predecessor who entered into the RSA dated July 28, 2020, and that together with their affiliates received 4% or more of New Common Stock (including shares to which they are entitled upon exercise of series A warrants of the Successor) pursuant to the Plan, or their affiliates. Under the Registration Rights Agreement, security holders have customary demand and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. Securityholders have the right to demand the Company to effectuate the distribution of any or all of its Registrable Securities (as defined in the Registration Rights Agreement) by means of an underwritten offering pursuant to an effective registration statement; provided, however, that the expected aggregate offering price is equal to or greater than $25.0 million or includes at least 20% of the then-outstanding Registrable Securities. 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. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter. 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 $1.1 million for the period September 19, 2020 through December 31, 2020 (Successor)

Stock Compensation

Stock Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock Compensation	Note 11. Stock Compensation Below is a description of stock compensation relating to both the Predecessor periods (2018, 2019 and January 1, 2020 through September 18, 2020) and the Successor period (September 19, 2020 through December 31, 2020). 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, 2020. 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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Stock-based compensation expense included in G&A $ 8,212 $ 4,111 $ 12,470 $ 11,951 Stock-based compensation capitalized 695 1,660 4,018 3,487 Total cost of stock-based compensation arrangements $ 8,907 $ 5,771 $ 16,488 $ 15,438 Income tax benefit recognized for stock-based compensation arrangements $ 2,053 $ 1,028 $ 3,118 $ 2,988 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, 2020, 4.0 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 over a three-year vesting period with delivery of the shares occurring at the end of the three-year vesting period. 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, 2020, there was $29.3 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 2.9 years. A summary of the status of our nonvested non-performance-based RSUs issued and the changes during the Successor period is presented below: Number Weighted Nonvested at September 19, 2020 (Successor) — $ — Granted 1,219,867 24.67 Vested — — Forfeited — — Nonvested at December 31, 2020 (Successor) 1,219,867 24.67 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 vest based on Denbury’s stock price reaching certain levels (based on the daily volume-weighted average common stock price on the New York Stock Exchange (“NYSE”) for any consecutive 60-day trading period), as shown in the table below, but delivery of the shares will not occur until the conclusion of the three Tier Stock Price Hurdle Cumulative Percentage of PSUs Granted Hereunder that Become Vested (1) 0 Less than $18.75 0% 1 $18.75 25% 2 $21.00 50% 3 $23.25 75% 4 $25.75 100% (1) If the 60-day volume-weighted average price falls between the Stock Price Hurdles in Tier 1, 2, 3 or 4, then the cumulative percentage of PSUs granted that become vested shall be calculated using straight-line interpolation between the corresponding percentages in the table above. 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, 2020, there was $16.6 million of unrecognized compensation expense related to the Successor’s nonvested PSU awards. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 0.2 years, though the underlying shares will not be delivered until the conclusion of the three Successor Period from Sept. 19, 2020 through Weighted average fair value of PSU awards granted $ 24.19 Risk-free interest rate 0.21 % Expected life 0.23 years Expected volatility 110.0 % Dividend yield — % A summary of the status of the nonvested PSU awards during the Successor period is as follows: Number Weighted Nonvested at September 19, 2020 (Successor) — $ — Granted 1,021,222 24.19 Vested — — Forfeited — — Nonvested at December 31, 2020 (Successor) 1,021,222 24.19 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, Compensation – Stock 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 (“SARs”) 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. SARs – Predecessor Prior to January 1, 2016, the Predecessor granted SARs settled in stock to employees. The SARs generally became exercisable over a three The following is a summary of the Predecessor’s SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2019 (Predecessor) 1,981,156 $ 9.12 Granted — — Exercised — — Forfeited — — Expired (580,087) 12.38 Cancelled (1,401,069) 7.77 Outstanding at September 18, 2020 (Predecessor) — — — $ — Exercisable at end of period — $ — — $ — As of December 31, 2018, all SARs vested and there was no remaining compensation cost to be recognized in future periods related to nonvested share-based SAR compensation arrangements. The grant-date fair value of SARs vested during the year ended December 31, 2018 was $1.1 million. There were no exercises of SARs for the period January 1, 2020 through September 18, 2020 (Predecessor) or the years ended December 31, 2019 and 2018. In connection with our emergence from bankruptcy, all SARs outstanding as of September 18, 2020 were 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 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 Year Ended December 31, In thousands 2019 2018 Fair value of restricted stock vested $ 707 $ 5,743 $ 23,060 A summary of the status of our nonvested non-performance-based restricted stock grants issued and the changes during the Predecessor period is presented below: Number Weighted Nonvested at December 31, 2019 (Predecessor) 12,407,436 $ 1.91 Granted — — Vested (2,743,473) 2.10 Forfeited — — Cancelled (9,663,963) 1.85 Nonvested at September 18, 2020 (Predecessor) — — 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 2018, 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”). As discussed above, in conjunction with our 2020 compensation adjustments, all outstanding Predecessor performance-based equity awards were canceled and replaced with a cash retention incentive in June 2020. 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 Year Ended December 31, 2019 2018 Weighted average fair value of Performance-Based TSR Awards granted $ 0.15 $ 1.95 $ 2.29 Risk-free interest rate 0.27 % 2.27 % 2.37 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 89.6 % 77.2 % 102.9 % Dividend yield — % — % — % A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the Predecessor period is as follows: Performance-Based Performance-Based Number Weighted Number Weighted Nonvested at December 31, 2019 (Predecessor) 1,838,584 $ 2.27 4,475,998 $ 2.65 Granted (1) — — 3,041,774 0.15 Vested (2) — — (742,996) 3.42 Forfeited (102,469) 2.28 (385,183) 1.26 Cancelled (1,736,115) 2.27 (6,389,593) 1.23 Nonvested at September 18, 2020 (Predecessor) — — — — (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares were between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of stock, in order to conserve available shares. (2) During 2020, the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 59% of target for each vested TSR performance-based award, representing 438,363 aggregate shares of Predecessor common stock issued. There were no vestings related to the Predecessor’s Operational performance-based awards during 2020. 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 Year Ended December 31, In thousands 2019 2018 Vesting date fair value of Performance-Based Operational Awards $ — $ — $ 595 Vesting date fair value of Performance-Based TSR Awards 79 2,783 542

Commodity Derivative Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2020
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 and expectation of future commodity prices. Under the terms of our Successor Bank Credit Agreement, by December 31, 2020, we were required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the twelve calendar months between August 1, 2020 through July 31, 2021 and 35% of our anticipated crude oil production for the second twelve calendar months between August 1, 2021 through July 31, 2022. As of December 31, 2020, we were in compliance with the hedging requirements of our 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, 2020, 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, 2020, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2021 Fixed-Price Swaps Jan – Dec NYMEX 26,000 $ 38.68 – 47.69 $ 42.54 $ — $ — $ — 2021 Collars Jan – Dec NYMEX 3,000 $ 45.00 – 51.30 $ — $ — $ 45.00 $ 50.95 2022 Fixed-Price Swaps Jan – June NYMEX 8,500 $ 42.65 – 45.50 $ 43.55 $ — $ — $ — (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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
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. As of December 31, 2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019: Fair Value Measurements Using: Quoted Prices Significant Significant In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2020 (Successor) 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) December 31, 2019 (Predecessor) Assets Oil derivative contracts – current $ — $ 8,503 $ 3,433 $ 11,936 Total Assets $ — $ 8,503 $ 3,433 $ 11,936 Liabilities Oil derivative contracts – current $ — $ (6,522) $ (1,824) $ (8,346) Total Liabilities $ — $ (6,522) $ (1,824) $ (8,346) Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated Statements of Operations. Level 3 Fair Value Measurements The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the periods indicated: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Fair value of Level 3 instruments, beginning of period $ — $ 1,609 $ 13,624 Transfers out of Level 3 — (1,609) — Fair value adjustments on commodity derivatives — — (8,205) Receipt on settlements of commodity derivatives — — (3,810) Fair value of Level 3 instruments, end of period $ — $ — $ 1,609 The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date $ — $ — $ (556) Instruments previously categorized as Level 3 included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX, whereby the implied volatilities utilized were developed using a benchmark, which was considered a significant unobservable input. The transfers between Level 3 and Level 2 during the period generally relate to changes in the significant relevant observable and unobservable inputs that are available for the fair value measurements of such financial instruments. 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. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of the Predecessor’s senior secured second lien notes, convertible senior notes, and senior subordinated notes were based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of December 31, 2020 and 2019, excluding pipeline financing obligations, was $70.0 million and $1,833.1 million, respectively, which decrease is primarily the result of the cancellation of $2.1 billion principal amount of debt as part of the Chapter 11 Restructuring. See Note 1, Nature of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code , for additional information. 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14. Commitments and Contingencies Commitments We have entered into long-term commitments to purchase CO 2 that are either non-cancelable or cancelable only upon the occurrence of specified future events. The commitments continue for up to 8 years. The price we will pay for CO 2 generally varies depending on the amount of CO 2 delivered and the price of oil. Our annual commitment under these contracts could range from $15 million to $23 million per year, assuming a $60 per Bbl NYMEX oil price. In addition, we have a processing fee contract related to our overriding royalty interest in the CO 2 at LaBarge Field. We estimate our annual commitment under this contract could range from $8 million to $11 million per year based on current processing fee rates. We are party to long-term contracts that require us to deliver CO 2 to our industrial CO 2 customers at various contracted prices. Based upon the maximum amounts deliverable as stated in the industrial contracts, we estimate that we may be obligated to deliver up to 673 Bcf of CO 2 to these customers over the next 14 years. The maximum volume required in any given year is approximately 276 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO 2 reserves at December 31, 2020, our current production capabilities and our projected levels of CO 2 usage for our own tertiary flooding program. Chapter 11 Proceedings On July 30, 2020, Denbury Resources Inc. and each of its wholly-owned subsidiaries filed for relief under chapter 11 of the Bankruptcy Code. The chapter 11 cases were administered jointly under the caption “ In re Denbury Resources Inc., et al. , Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered the Confirmation Order and on the Emergence Date, all of the conditions of the Plan were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. On September 30, 2020, the Bankruptcy Court closed the chapter 11 cases of each of Denbury Inc.’s wholly-owned subsidiaries. The chapter 11 case captioned “ In re Denbury Resources Inc., et al. , Case No. 20-33801” will remain pending until the final resolution of all outstanding claims. 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. Riley Ridge Helium Supply Contract Claim As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). As the gas processing facility was shut-in during mid-2014 due to significant technical issues, we were not able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract. On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but such condition only excused the Company’s performance for a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for all other time periods for performance from contract commencement to the close of evidence (November 29, 2017). On December 4, 2020, the Wyoming Supreme Court entered a judgment affirming the trial court’s ruling on all counts and, as a result, the Company paid total liquidated damages (including interest) of $52.1 million to APMTG on December 23, 2020 in full satisfaction of all claims. The Company had previously recorded an accrual for these costs in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. 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.

Additional Balance Sheet Detail

Additional Balance Sheet Details	12 Months Ended
	Dec. 31, 2020
Text Block [Abstract]
Additional Balance Sheet Details	Note 15. Additional Balance Sheet Details Rollforward of Allowance for Doubtful Accounts Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Dec. 31, 2018 Beginning balance $ 22,146 $ 17,137 $ 17,070 $ 229 Provision for doubtful accounts 1,060 5,297 68 16,911 Write-offs — (288) (1) (70) Ending balance $ 23,206 $ 22,146 $ 17,137 $ 17,070 Accounts Payable and Accrued Liabilities Successor Predecessor In thousands December 31, 2020 December 31, 2019 Accrued general and administrative expenses $ 21,825 $ 21,838 Accrued lease operating expenses 21,294 26,686 Accounts payable 18,629 29,077 Taxes payable 17,221 21,274 Accrued compensation 7,512 36,366 Accrued exploration and development costs 1,861 7,811 Accrued interest 1,833 25,253 Other 22,496 15,527 Total $ 112,671 $ 183,832

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 16. Supplemental Cash Flow Information Supplemental Cash Flow Information Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Supplemental cash flow information Cash paid for interest, expensed $ 813 $ 29,357 $ 72,842 $ 50,076 Cash paid for interest, capitalized 1,261 22,885 36,671 37,079 Cash paid for interest, treated as a reduction of debt — 46,417 85,303 79,606 Cash paid for income taxes — 453 2,361 492 Cash received from income tax refunds 10,457 1,932 9,820 8,280 Noncash investing and financing activities Increase in asset retirement obligations 23,398 4,328 13,560 4,499 Increase (decrease) in liabilities for capital expenditures 1,867 (12,809) (17,740) 14,600 Conversion of convertible senior notes into common stock — 11,501 — 162,004

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	Note 17. Subsequent Event On March 3, 2021, we closed on an agreement to acquire working interest positions in the Big Sand Draw and Beaver Creek oil fields located in Wyoming, including surface facilities and a CO 2 transportation pipeline to the acquired fields, for a cash purchase price of $12 million before closing adjustments.

Nature of Operations and Summ_2

Nature of Operations and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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 on producing oil from mature oil fields in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO 2 EOR and the emerging CCUS industry, supported by the Company’s CO 2 EOR technical and operational expertise and its extensive CO 2 pipeline infrastructure. The utilization of captured industrial-sourced CO 2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO 2 emissions within the decade. 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 CO 2 reserves used to compute depletion of CO 2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; (8) estimates made in the calculation of income taxes; and (9) 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, 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 Predecessor In thousands December 31, 2020 December 31, 2019 Cash and cash equivalents $ 518 $ 516 Restricted cash, current 1,000 — Restricted cash included in other assets 40,730 32,529 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 42,248 $ 33,045
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 and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $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 (“COVID-19”) 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 CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $55.55 at December 31, 2019, $40.08 at September 18, 2020, and $35.84 at December 31, 2020. Primarily as a result of these commodity price declines, 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 Predecessor periods of 2018 or 2019. 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 CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs until we are able to recognize proved reserves associated with the development project. After we see a production response to the CO 2 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	CO 2 Properties We own and produce CO 2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO 2 to third parties when it is produced and sold. Expenses related to the production of CO 2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO 2 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 CO 2 (see Tertiary Injection Costs above for further discussion). Costs incurred to search for CO 2 are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO 2 properties” on our Consolidated Balance Sheets. Capitalized CO 2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. Pipelines CO 2 used in our tertiary floods is transported to our fields through CO 2 pipelines. Costs of CO 2 pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 43 years. Capitalized costs include $0.7 million of CO 2 pipelines as of December 31, 2020, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2020. 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 and furniture and fixtures are generally depreciated over a useful life of one one 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 for the Predecessor period primarily consisted of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming, and for the Successor period represent amounts assigned in fresh start accounting to long-term contracts to sell CO 2 to industrial customers. We amortize the CO 2 contract intangible assets on a straight-line basis over their estimated useful lives, which range from seven Successor Predecessor In thousands December 31, 2020 December 31, 2019 Long-term contracts to sell CO 2 to industrial customers $ 97,943 $ — Other intangibles 2,167 37,668 Accumulated amortization (2,748) (15,529) Net book value $ 97,362 $ 22,139 As of December 31, 2020, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2021 $ 9,117 2022 9,117 2023 9,117 2024 9,117 2025 9,117
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 CO 2 properties and pipelines, and for the Successor period also included long-term contracts to sell CO 2 to industrial customers. Given the significant declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region) as of March 31, 2020 (Predecessor). 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 CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020 (Predecessor). 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. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and no impairment was recorded. Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO 2 , projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and September 18, 2020 (Predecessor periods) and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, no impairment test was performed for the second quarter of 2020 or for the period ending September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our long-lived assets being recorded at their fair value at the Emergence Date (see Note 2, Fresh Start Accounting
Asset Retirement Obligations	Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO 2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool. 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 and expectation of future commodity prices. Under the terms of our Successor Bank Credit Agreement, by December 31, 2020, we were required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the twelve calendar months between August 1, 2020 through July 31, 2021 and 35% of our anticipated crude oil production for the second twelve calendar months between August 1, 2021 through July 31, 2022. As of December 31, 2020, we were in compliance with the hedging requirements of our 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, 2020, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset
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.
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 period consist of nonvested restricted stock units, nonvested performance stock units, and warrants, and during the Predecessor period have historically consisted of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible. The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Numerator Net income (loss) – basic $ (50,658) $ (1,432,578) $ 216,959 $ 322,698 Effect of potentially dilutive securities Interest on convertible senior notes including amortization of discount, net of tax — — 14,134 539 Net income (loss) – diluted $ (50,658) $ (1,432,578) $ 231,093 $ 323,237 Denominator Weighted average common shares outstanding – basic 50,000 495,560 459,524 432,483 Effect of potentially dilutive securities Restricted stock and performance-based equity awards — — 2,396 6,500 Convertible senior notes (1) — — 48,421 17,186 Weighted average common shares outstanding – diluted 50,000 495,560 510,341 456,169 (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 ). Time-vesting restricted stock is included in basic weighted average common shares from the vesting date (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares for the years ended December 31, 2019 and 2018, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods. In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Stock appreciation rights — 1,007 2,027 2,743 Restricted stock and performance-based equity awards — 7,280 5,505 1,234 Convertible senior notes — 87,888 — — Restricted stock units (1) 328 — — — Warrants (2) 5,526 — — —
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 Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Effective January 1, 2020, we adopted ASU 2016-13. The implementation of this standard did not have a material impact on our consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. Effective January 1, 2020, we adopted ASU 2018-13. The implementation of this standard did not have a material impact on our consolidated financial statements or footnote disclosures. Leases. During the Predecessor period, effective January 1, 2019, we adopted FASB ASU 2016-02, Leases , and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842 , using the modified retrospective method with an application date of January 1, 2019. For a discussion of our current accounting for lease contracts, see Note 5, Leases . Not Yet Adopted Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this ASU were effective upon issuance and generally can be applied to applicable contract modifications through December 31, 2022. Currently, our Successor Bank Credit Agreement is our only contract that makes reference to a LIBOR rate and the agreement outlines the specific procedures that will be undertaken once an appropriate alternative benchmark is identified. We do not expect this guidance to have a significant impact on our consolidated financial statements and related footnote disclosures. Income Taxes. In December 2019, the FASB issued 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. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and early adoption is permitted. We do not expect the adoption of this guidance to have a significant 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 CO 2 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 the risks and rewards of ownership (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 CO 2 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 CO 2 contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made 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 CO 2 sales and transportation contracts, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as 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 7 years, with certain land leases having remaining terms up to 49 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.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 over a three-year vesting period with delivery of the shares occurring at the end of the three-year vesting period. 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. SARs – Predecessor Prior to January 1, 2016, the Predecessor granted SARs settled in stock to employees. The SARs generally became exercisable over a three 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 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 2018, 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”). As discussed above, in conjunction with our 2020 compensation adjustments, all outstanding Predecessor performance-based equity awards were canceled and replaced with a cash retention incentive in June 2020.
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. As of December 31, 2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

Nature of Operations and Summ_3

Nature of Operations and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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 Predecessor In thousands December 31, 2020 December 31, 2019 Cash and cash equivalents $ 518 $ 516 Restricted cash, current 1,000 — Restricted cash included in other assets 40,730 32,529 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 42,248 $ 33,045
Schedule of intangible assets	The following table summarizes the carrying value of our intangible assets as of December 31, 2020 and 2019: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Long-term contracts to sell CO 2 to industrial customers $ 97,943 $ — Other intangibles 2,167 37,668 Accumulated amortization (2,748) (15,529) Net book value $ 97,362 $ 22,139
Schedule of future amortization expense of intangible assets	As of December 31, 2020, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2021 $ 9,117 2022 9,117 2023 9,117 2024 9,117 2025 9,117
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: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Numerator Net income (loss) – basic $ (50,658) $ (1,432,578) $ 216,959 $ 322,698 Effect of potentially dilutive securities Interest on convertible senior notes including amortization of discount, net of tax — — 14,134 539 Net income (loss) – diluted $ (50,658) $ (1,432,578) $ 231,093 $ 323,237 Denominator Weighted average common shares outstanding – basic 50,000 495,560 459,524 432,483 Effect of potentially dilutive securities Restricted stock and performance-based equity awards — — 2,396 6,500 Convertible senior notes (1) — — 48,421 17,186 Weighted average common shares outstanding – diluted 50,000 495,560 510,341 456,169 (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 securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Stock appreciation rights — 1,007 2,027 2,743 Restricted stock and performance-based equity awards — 7,280 5,505 1,234 Convertible senior notes — 87,888 — — Restricted stock units (1) 328 — — — Warrants (2) 5,526 — — — (1) Shares represent the impact over the Successor period of the approximately 1.2 million shares of the Successor’s common stock issuable upon full vesting of the restricted stock unit awards issued on December 4, 2020 pursuant to the 2020 Omnibus Stock and Incentive Plan (see Note 11, Stock Compensation ). (2) Shares represent the impact over the Successor period of the approximately 5.5 million shares of the Successor’s common stock issuable upon full exercise of the series A warrants, at an exercise price of $32.59 per share, and series B warrants, at an exercise price of $35.41 per share, which were issued pursuant to the Plan to the Predecessor’s convertible senior notes, senior subordinated notes, and equity holders. The dilution from exercise of the series A or series B warrants could be reduced to the extent warrants are exercised on a cashless basis.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2020
Reconciliation of Reorganization Value	The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date: In thousands Sept. 18, 2020 Enterprise value $ 1,280,856 Plus: Cash and cash equivalents 45,585 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 thousands Sept. 18, 2020 Enterprise value $ 1,280,856 Plus: Cash and cash equivalents 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
Schedule Of Reorganization Adjustments	The following table summarizes the losses (gains) on reorganization items, net: Predecessor Period from In thousands 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 4,601 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 thousands Predecessor Reorganization Adjustments Fresh Start Adjustments Successor Assets Current assets Cash and cash equivalents $ 73,372 $ (27,787) (1) $ — $ 45,585 Restricted cash — 10,662 (2) — 10,662 Accrued production receivable 112,832 — — 112,832 Trade and other receivables, net 36,221 — — 36,221 Derivative assets 32,635 — — 32,635 Other current assets 12,968 (539) (3) — 12,429 Total current assets 268,028 (17,664) — 250,364 Property and equipment Oil and natural gas properties (using full cost accounting) Proved properties 11,723,546 — (10,941,313) 782,233 Unevaluated properties 650,553 — (538,570) 111,983 CO 2 properties 1,198,515 — (1,011,169) 187,346 Pipelines 2,339,864 — (2,207,246) 132,618 Other property and equipment 201,565 — (104,152) 97,413 Less accumulated depletion, depreciation, amortization and impairment (12,864,141) — 12,864,141 — Net property and equipment 3,249,902 — (1,938,309) (10) 1,311,593 Operating lease right-of-use assets 1,774 — 69 (10) 1,843 Derivative assets 501 — — 501 Intangible assets, net 20,405 — 79,678 (11) 100,083 Other assets 81,809 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 thousands Predecessor Reorganization Adjustments Fresh Start Adjustments Successor 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 payable 39,372 16,705 (6) — 56,077 Derivative liabilities 8,613 — — 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 liabilities 115,774 193,454 4,073 313,301 Long-term liabilities Long-term debt, net of current portion 140,000 42,610 (6) (25,151) (14) 157,459 Asset retirement obligations 2,727 180,408 (6) (24,697) (10) 158,438 Derivative liabilities 295 — — 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 compromise 143,022 645,024 (445,359) 342,687 Liabilities subject to compromise 2,823,506 (2,823,506) (6) — — Commitments and contingencies (Note 14) Stockholders’ equity Predecessor preferred stock — — — — Predecessor common stock 510 (510) (7) — — Predecessor paid-in capital in excess of par 2,764,915 (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 proceeds 140,000 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 compromise 101,431 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 notes 234,015 Senior subordinated notes 251,480 Total settled liabilities subject to compromise 2,114,952 Reinstated liabilities subject to compromise Current maturities of long-term debt 73,199 Accounts payable and accrued liabilities 101,431 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 Deferred tax liabilities 289,389 Operating lease liabilities, long-term 515 Other long-term liabilities 3,540 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 (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 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) 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 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 $ 3,639,409 Fresh Start Adjustments (10) Reflects fair value adjustments to our (i) oil and natural gas properties, CO 2 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 CO 2 to industrial customers. (12) Reflects fair value adjustments to our other assets as follows: In thousands Fair value adjustment for CO 2 and oil pipeline line-fill $ (3,698) Fair value adjustments for escrow accounts 671 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 obligation 689 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 Debt – Restructuring 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.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table summarizes our revenues by product type: Successor Predecessor Period from Period from Year Ended December 31, In thousands 2019 2018 Oil sales $ 199,769 $ 489,251 $ 1,205,083 $ 1,412,358 Natural gas sales 1,339 2,850 6,937 10,231 CO 2 sales and transportation fees 9,419 21,049 34,142 31,145 Oil marketing revenues 5,376 8,543 14,198 1,921 Total revenues $ 215,903 $ 521,693 $ 1,260,360 $ 1,455,655

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
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 Predecessor In thousands December 31, 2020 December 31, 2019 Operating leases Operating lease right-of-use assets $ 20,342 $ 34,099 Operating lease liabilities – current $ 1,350 $ 6,901 Operating lease liabilities – long-term 19,460 41,932 Total operating lease liabilities $ 20,810 $ 48,833
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 Predecessor December 31, 2020 December 31, 2019 Weighted average remaining lease term 6.3 years 5.7 years Weighted average discount rate 5.6 % 6.7 %
Schedule of Lease Costs	The following table summarizes the components of lease costs and sublease income: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Income Statement Dec. 31, 2019 Operating lease cost General and administrative expenses $ 872 $ 5,683 $ 8,924 Lease operating expenses 158 214 58 CO 2 operating and discovery expenses 14 37 5 $ 1,044 $ 5,934 $ 8,987 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ 3 $ 9 $ 1,188 Interest on lease liabilities Interest expense 1 3 40 Total finance lease cost $ 4 $ 12 $ 1,228 Sublease income General 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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 341 $ 7,341 $ 10,995 Operating cash flows from interest on finance leases 1 3 40 Financing cash flows from finance leases 78 10 1,275 Right-of-use assets obtained in exchange for lease obligations Operating leases 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, 2020: Operating In thousands Leases 2021 $ 2,496 2022 4,149 2023 4,135 2024 4,111 2025 4,149 Thereafter 6,263 Total minimum lease payments 25,303 Less: Amount representing interest (4,493) Present value of minimum lease liabilities $ 20,810

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Changes In Asset Retirement Obligations	The following table summarizes the changes in our asset retirement obligations: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Beginning asset retirement obligations $ 163,368 $ 181,760 $ 176,585 Liabilities incurred and assumed during period 738 736 4,354 Revisions in estimated retirement obligations 22,660 3,592 9,206 Liabilities settled and sold during period (3,439) (10,041) (24,342) Accretion expense 2,954 11,329 15,957 Fresh start accounting adjustment — (24,008) — Ending asset retirement obligations 186,281 163,368 181,760 Less: current asset retirement obligations (1) (6,943) (4,930) (4,652) Long-term asset retirement obligations $ 179,338 $ 158,438 $ 177,108 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Unevaluated Property (Tables)

Unevaluated Property (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, and the year in which the costs were incurred follows: December 31, 2020 Costs Incurred During: In thousands Successor 2020 Fresh Start Adjustments (Sept. 18, 2020) (1) Total Property acquisition costs $ — $ 84,019 $ 84,019 Exploration and development 46 — 46 Capitalized interest 1,239 — 1,239 Total $ 1,285 $ 84,019 $ 85,304 (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, 2020.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Components of long-term debt	The table below reflects long-term debt outstanding as of December 31, 2020 and 2019: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Successor Senior Secured Bank Credit Agreement $ 70,000 $ — Predecessor Senior Secured Bank Credit Agreement — — 9% Senior Secured Second Lien Notes due 2021 — 614,919 9¼% Senior Secured Second Lien Notes due 2022 — 455,668 7¾% Senior Secured Second Lien Notes due 2024 — 531,821 7½% Senior Secured Second Lien Notes due 2024 — 20,641 6⅜% Convertible Senior Notes due 2024 — 245,548 6⅜% Senior Subordinated Notes due 2021 — 51,304 5½% Senior Subordinated Notes due 2022 — 58,426 4⅝% Senior Subordinated Notes due 2023 — 135,960 Pipeline financings 68,008 167,439 Total debt principal balance 138,008 2,281,726 Debt discount — (101,767) Future interest payable — 164,914 Debt issuance costs — (10,009) Total debt, net of debt issuance costs and discount 138,008 2,334,864 Less: current maturities of long-term debt (68,008) (102,294) Long-term debt and capital lease obligations $ 70,000 $ 2,232,570
Indebtedness repayable over the next five years and thereafter	At December 31, 2020, our indebtedness is payable over the next five years and thereafter as follows: In thousands 2021 $ 68,008 2022 — 2023 — 2024 70,000 2025 — Thereafter — Total indebtedness $ 138,008

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	Our income tax provision (benefit) is as follows: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Current income tax expense (benefit) Federal $ — $ (6,407) $ 2,645 $ (17,885) State 30 (853) 1,236 1,884 Total current income tax expense (benefit) 30 (7,260) 3,881 (16,001) Deferred income tax expense (benefit) Federal — (319,011) 89,950 93,395 State (2,556) (89,858) 10,521 9,839 Total deferred income tax expense (benefit) (2,556) (408,869) 100,471 103,234 Total income tax expense (benefit) $ (2,526) $ (416,129) $ 104,352 $ 87,233
Deferred Tax Assets And Liabilities	Significant components of our deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows: Successor Predecessor In thousands December 31, 2020 December 31, 2019 Deferred tax assets Property and equipment $ 59,207 $ — Loss and tax credit carryforwards – state 55,979 52,917 Accrued liabilities and other reserves 15,632 29,788 Derivative contracts 13,090 — Lease liabilities 6,354 10,841 Business interest expense carryforward — 24,513 Business credit carryforwards — 71,555 Unrecognized gain and original issue discount on debt exchange — 41,556 Other 4,092 15,664 Valuation allowances (129,408) (77,215) Total deferred tax assets 24,946 169,619 Deferred tax liabilities CO 2 and other contracts (20,030) — Operating lease right-of-use assets (6,190) (7,780) Property and equipment — (569,254) Derivative contracts — (1,120) Other — (1,695) Total deferred tax liabilities (26,220) (579,849) Total net deferred tax liability $ (1,274) $ (410,230)
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: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Income tax provision calculated using the federal statutory income tax rate $ (11,169) $ (388,228) $ 67,475 $ 86,086 State income taxes, net of federal income tax benefit (2,532) (86,937) 7,435 11,968 Tax shortfall (windfall) on stock-based compensation deduction — (1,502) 1,912 (1,565) Valuation allowance 9,653 19,344 26,122 (42) Tax attributes reduction – net of CODI exclusion — 31,667 — — Enhanced oil recovery tax credits generated — — — (10,818) Other 1,522 9,527 1,408 1,604 Total income tax expense (benefit) $ (2,526) $ (416,129) $ 104,352 $ 87,233
Tax Valuation Allowance
Valuation Allowance [Line Items]
Changes in Valuation Allowance	The changes in our valuation allowance are detailed below: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Dec. 31, 2018 Beginning balance $ 129,840 $ 77,215 $ 51,093 $ 51,134 Charges 2,269 77,138 26,122 — Deductions (2,701) (24,513) — (41) Ending balance $ 129,408 $ 129,840 $ 77,215 $ 51,093

Stock Compensation (Tables)

Stock Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Stock Compensation
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 Weighted Nonvested at September 19, 2020 (Successor) — $ — Granted 1,219,867 24.67 Vested — — Forfeited — — Nonvested at December 31, 2020 (Successor) 1,219,867 24.67
Summary of SARs activity	The following is a summary of the Predecessor’s SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2019 (Predecessor) 1,981,156 $ 9.12 Granted — — Exercised — — Forfeited — — Expired (580,087) 12.38 Cancelled (1,401,069) 7.77 Outstanding at September 18, 2020 (Predecessor) — — — $ — Exercisable at end of period — $ — — $ —
Schedule of stock-based compensation costs	The following table sets forth stock-based compensation costs for the periods indicated: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Stock-based compensation expense included in G&A $ 8,212 $ 4,111 $ 12,470 $ 11,951 Stock-based compensation capitalized 695 1,660 4,018 3,487 Total cost of stock-based compensation arrangements $ 8,907 $ 5,771 $ 16,488 $ 15,438 Income tax benefit recognized for stock-based compensation arrangements $ 2,053 $ 1,028 $ 3,118 $ 2,988
Performance Share Units
Stock Compensation
Performance and vesting terms under performance share unit awards	The PSU awards vest based on Denbury’s stock price reaching certain levels (based on the daily volume-weighted average common stock price on the New York Stock Exchange (“NYSE”) for any consecutive 60-day trading period), as shown in the table below, but delivery of the shares will not occur until the conclusion of the three Tier Stock Price Hurdle Cumulative Percentage of PSUs Granted Hereunder that Become Vested (1) 0 Less than $18.75 0% 1 $18.75 25% 2 $21.00 50% 3 $23.25 75% 4 $25.75 100% (1) If the 60-day volume-weighted average price falls between the Stock Price Hurdles in Tier 1, 2, 3 or 4, then the cumulative percentage of PSUs granted that become vested shall be calculated using straight-line interpolation between the corresponding percentages in the table above.
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 Weighted average fair value of PSU awards granted $ 24.19 Risk-free interest rate 0.21 % Expected life 0.23 years Expected volatility 110.0 % Dividend yield — %
Schedule of nonvested performance stock unit awards activity	A summary of the status of the nonvested PSU awards during the Successor period is as follows: Number Weighted Nonvested at September 19, 2020 (Successor) — $ — Granted 1,021,222 24.19 Vested — — Forfeited — — Nonvested at December 31, 2020 (Successor) 1,021,222 24.19
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 Year Ended December 31, In thousands 2019 2018 Fair value of restricted stock vested $ 707 $ 5,743 $ 23,060
Summary of non-performance-based restricted stock activity	A summary of the status of our nonvested non-performance-based restricted stock grants issued and the changes during the Predecessor period is presented below: Number Weighted Nonvested at December 31, 2019 (Predecessor) 12,407,436 $ 1.91 Granted — — Vested (2,743,473) 2.10 Forfeited — — Cancelled (9,663,963) 1.85 Nonvested at September 18, 2020 (Predecessor) — —
Performance-Based Equity Awards
Stock Compensation
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 Year Ended December 31, 2019 2018 Weighted average fair value of Performance-Based TSR Awards granted $ 0.15 $ 1.95 $ 2.29 Risk-free interest rate 0.27 % 2.27 % 2.37 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 89.6 % 77.2 % 102.9 % Dividend yield — % — % — %
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 Year Ended December 31, In thousands 2019 2018 Vesting date fair value of Performance-Based Operational Awards $ — $ — $ 595 Vesting date fair value of Performance-Based TSR Awards 79 2,783 542
Summary of nonvested performance-based equity awards	A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the Predecessor period is as follows: Performance-Based Performance-Based Number Weighted Number Weighted Nonvested at December 31, 2019 (Predecessor) 1,838,584 $ 2.27 4,475,998 $ 2.65 Granted (1) — — 3,041,774 0.15 Vested (2) — — (742,996) 3.42 Forfeited (102,469) 2.28 (385,183) 1.26 Cancelled (1,736,115) 2.27 (6,389,593) 1.23 Nonvested at September 18, 2020 (Predecessor) — — — — (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares were between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of stock, in order to conserve available shares. (2) During 2020, the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 59% of target for each vested TSR performance-based award, representing 438,363 aggregate shares of Predecessor common stock issued. There were no vestings related to the Predecessor’s Operational performance-based awards during 2020.

Commodity Derivative Contracts

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2021 Fixed-Price Swaps Jan – Dec NYMEX 26,000 $ 38.68 – 47.69 $ 42.54 $ — $ — $ — 2021 Collars Jan – Dec NYMEX 3,000 $ 45.00 – 51.30 $ — $ — $ 45.00 $ 50.95 2022 Fixed-Price Swaps Jan – June NYMEX 8,500 $ 42.65 – 45.50 $ 43.55 $ — $ — $ — (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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019: Fair Value Measurements Using: Quoted Prices Significant Significant In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2020 (Successor) 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) December 31, 2019 (Predecessor) Assets Oil derivative contracts – current $ — $ 8,503 $ 3,433 $ 11,936 Total Assets $ — $ 8,503 $ 3,433 $ 11,936 Liabilities Oil derivative contracts – current $ — $ (6,522) $ (1,824) $ (8,346) Total Liabilities $ — $ (6,522) $ (1,824) $ (8,346)
Changes in fair value of Level 3 assets and liabilities	The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the periods indicated: Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Fair value of Level 3 instruments, beginning of period $ — $ 1,609 $ 13,624 Transfers out of Level 3 — (1,609) — Fair value adjustments on commodity derivatives — — (8,205) Receipt on settlements of commodity derivatives — — (3,810) Fair value of Level 3 instruments, end of period $ — $ — $ 1,609 The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date $ — $ — $ (556)

Additional Balance Sheet Deta_2

Additional Balance Sheet Details (Tables)	12 Months Ended
	Dec. 31, 2020
Text Block [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities Successor Predecessor In thousands December 31, 2020 December 31, 2019 Accrued general and administrative expenses $ 21,825 $ 21,838 Accrued lease operating expenses 21,294 26,686 Accounts payable 18,629 29,077 Taxes payable 17,221 21,274 Accrued compensation 7,512 36,366 Accrued exploration and development costs 1,861 7,811 Accrued interest 1,833 25,253 Other 22,496 15,527 Total $ 112,671 $ 183,832
Trade and Other Receivables, Net
Valuation Allowance [Line Items]
Changes in Valuation Allowance	Rollforward of Allowance for Doubtful Accounts Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended In thousands Dec. 31, 2019 Dec. 31, 2018 Beginning balance $ 22,146 $ 17,137 $ 17,070 $ 229 Provision for doubtful accounts 1,060 5,297 68 16,911 Write-offs — (288) (1) (70) Ending balance $ 23,206 $ 22,146 $ 17,137 $ 17,070

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Successor Predecessor Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Year Ended December 31, In thousands 2019 2018 Supplemental cash flow information Cash paid for interest, expensed $ 813 $ 29,357 $ 72,842 $ 50,076 Cash paid for interest, capitalized 1,261 22,885 36,671 37,079 Cash paid for interest, treated as a reduction of debt — 46,417 85,303 79,606 Cash paid for income taxes — 453 2,361 492 Cash received from income tax refunds 10,457 1,932 9,820 8,280 Noncash investing and financing activities Increase in asset retirement obligations 23,398 4,328 13,560 4,499 Increase (decrease) in liabilities for capital expenditures 1,867 (12,809) (17,740) 14,600 Conversion of convertible senior notes into common stock — 11,501 — 162,004

Nature of Ops and Sign. Acctg P

Nature of Ops and Sign. Acctg Policies (Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 518		$ 516
Restricted cash, current	1,000		0
Restricted cash included in other assets	40,730		32,529
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 42,248	$ 95,114	$ 33,045	$ 54,949	$ 15,992

Nature of Ops and Sign. Acctg_2

Nature of Ops and Sign. Acctg Policies (Intangibles) (Details 1) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Long-term contracts to sell CO2 to industrial customers	$ 97,943	$ 0
Other intangibles	2,167	37,668
Accumulated amortization	(2,748)	(15,529)
Net book value	$ 97,362	$ 22,139

Nature of Ops and Sign. Acctg_3

Nature of Ops and Sign. Acctg Policies (Estimated Amortization Expense for Intangibles) (Details 2) $ in Thousands	Dec. 31, 2020USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	$ 9,117
2022	9,117
2023	9,117
2024	9,117
2025	$ 9,117

Nature of Ops and Sign. Acctg_4

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, 2019		Dec. 31, 2018
Numerator
Net income (loss) - basic	$ (50,658)	$ (1,432,578)		$ 216,959		$ 322,698
Interest on convertible senior notes including amortization of discount, net of tax	0	0		14,134		539
Net income (loss) - diluted	$ (50,658)	$ (1,432,578)		$ 231,093		$ 323,237
Denominator
Weighted average common shares outstanding – basic	50,000	495,560		459,524		432,483
Restricted stock and performance-based equity awards	0	0		2,396		6,500
Convertible senior notes	0	0	[1]	48,421	[1]	17,186	[1]
Weighted average common shares outstanding – diluted	50,000	495,560		510,341		456,169
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 ).

Nature of Ops and Sign. Acctg_5

Nature of Ops and Sign. Acctg Policies (Antidilutive Securities) (Details 4) - $ / shares	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2020		Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Series A Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share
Shares issuable upon exercise of warrants			2,631,579
Exercise price of warrants	$ 32.59		$ 32.59
Series B Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share
Shares issuable upon exercise of warrants			2,894,740
Exercise price of warrants	$ 35.41		$ 35.41
Stock appreciation rights
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0		1,007,000	2,027,000	2,743,000
Restricted stock and performance-based equity awards
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0		7,280,000	5,505,000	1,234,000
Convertible senior notes
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0		87,888,000	0	0
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	328,000	[1]	0	0	0
Number of shares issuable upon full vesting of awards	1,200,000
Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5,526,000	[2]	0	0	0
Shares issuable upon exercise of warrants	5,500,000
[1]	Shares represent the impact over the Successor period of the approximately 1.2 million shares of the Successor’s common stock issuable upon full vesting of the restricted stock unit awards issued on December 4, 2020 pursuant to the 2020 Omnibus Stock and Incentive Plan (see Note 11, Stock Compensation ).
[2]	Shares represent the impact over the Successor period of the approximately 5.5 million shares of the Successor’s common stock issuable upon full exercise of the series A warrants, at an exercise price of $32.59 per share, and series B warrants, at an exercise price of $35.41 per share, which were issued pursuant to the Plan to the Predecessor’s convertible senior notes, senior subordinated notes, and equity holders. The dilution from exercise of the series A or series B warrants could be reduced to the extent warrants are exercised on a cashless basis.

Nature of Ops and Sign. Acctg_6

Nature of Ops and Sign. Acctg Policies (Plan of Reorganization) (Details Textuals) - USD ($)	Sep. 18, 2020	Dec. 31, 2020	Jul. 28, 2020	Dec. 31, 2019
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		750,000,000
Successor common stock, par value	$ 0.001	$ 0.001		$ 0.001
Successor preferred stock, shares authorized	50,000,000	50,000,000		25,000,000
Successor preferred stock, par value	$ 0.001	$ 0.001		$ 0.001
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
Exercise price of warrants	$ 32.59	$ 32.59
Series A Warrants | Maximum
Plan of Chapter 11 Reorganization [Line Items]
Equity percentage under plan of reorganization	5.00%
Series B Warrants
Plan of Chapter 11 Reorganization [Line Items]
Number of warrants outstanding	2,894,740
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%
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%

Nature of Ops and Sign. Acctg_7

Nature of Ops and Sign. Acctg Policies (Details Textuals 2) shares in Millions	Sep. 30, 2020	May 31, 2018shares	Dec. 31, 2020USD ($)	Sep. 18, 2020USD ($)	Jun. 30, 2020USD ($)shares	Mar. 31, 2020USD ($)	Sep. 18, 2020USD ($)	Dec. 31, 2020USD ($)$ / Barrel	Sep. 18, 2020$ / Barrel	Dec. 31, 2019USD ($)$ / Barrel	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Line Items]
Oil and Gas, Average Sale Price | $ / Barrel								35.84	40.08	55.55
Ceiling test write-downs of oil and gas properties			$ 1,006,000				$ 996,658,000			$ 0	$ 0
Costs related to CO2 pipelines not placed into service			700,000					$ 700,000
Amortization of intangible assets			$ 2,700,000				1,700,000			2,400,000	2,400,000
Carrying value of long-lived assets						$ 1,300,000,000
Allowance for loan receivable											$ 16,900,000
Issued pursuant to notes conversion, shares | shares		55.2			7.4
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		7 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life of intangible CO2 contracts	14 years		14 years
Pipelines | Minimum
Property, Plant and Equipment [Line Items]
Useful life	20 years		20 years
Pipelines | Maximum
Property, Plant and Equipment [Line Items]
Useful life	43 years		43 years
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Useful life			1 year
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Useful life			6 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			6 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

Nature of Ops and Sign. Acctg_8

Nature of Ops and Sign. Acctg Policies (Major Customers) (Details Textuals 3)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Plains Marketing LP
Product Information [Line Items]
Revenue from major customer (percentage)	30.00%	30.00%	32.00%	24.00%
Marathon Petroleum Company
Product Information [Line Items]
Revenue from major customer (percentage)	13.00%	12.00%
Hunt Crude Oil Company
Product Information [Line Items]
Revenue from major customer (percentage)	12.00%	12.00%	11.00%	10.00%
Sunoco Inc
Product Information [Line Items]
Revenue from major customer (percentage)			11.00%

Fresh Start Accounting (Enterpr

Fresh Start Accounting (Enterprise Value to Equity Value) (Details) $ in Thousands	Sep. 18, 2020USD ($)
Reorganizations [Abstract]
Enterprise value	$ 1,280,856
Plus: Cash and cash equivalents	45,585
Postconfirmation Debt	(231,022)
Equity value	$ 1,095,419

Fresh Start Accounting (Reconci

Fresh Start Accounting (Reconciliation of Reorganization Value) (Details 1) $ in Thousands	Sep. 18, 2020USD ($)
Reorganizations [Abstract]
Enterprise value	$ 1,280,856
Plus: Cash and cash equivalents	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

Fresh Start Accounting (Reorgan

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, 2019	Dec. 31, 2018
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

Fresh Start Accounting (Condens

Fresh Start Accounting (Condensed Consolidated Balance Sheet) (Details 3) - USD ($)	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents		$ 73,372,000
Accrued production receivable		112,832,000
Trade and other receivables		36,221,000
Derivative assets		32,635,000
Other current assets		12,968,000
Total current assets		268,028,000
Proved properties		11,723,546,000
Unevaluated properties		650,553,000
CO2 properties		1,198,515,000
Pipelines		2,339,864,000
Other property and equipment	$ 86,610,000	201,565,000	$ 212,334,000
Less accumulated depletion, depreciation, amortization and impairment		(12,864,141,000)
Net property and equipment		3,249,902,000
Operating lease right-of-use assets		1,774,000
Derivative assets		501,000
Intangible assets, net		20,405,000
Other assets		81,809,000
Total assets		3,622,419,000
Accounts payable and accrued liabilities		67,789,000
Oil and gas production payable		39,372,000
Oil and gas production payable		16,705,000
Derivative liabilities		8,613,000
Total current liabilities		115,774,000
Long-term debt, net of current portion		140,000,000
Asset retirement obligations		2,727,000
Derivative liabilities		295,000
Total long-term liabilities not subject to compromise		143,022,000
Liabilities subject to compromise		2,823,506,000
Predecessor common stock		510,000
Predecessor paid-in capital in excess of par		2,764,915,000
Predecessor treasury stock, at cost		(6,202,000)
Successor common stock		50,000
Successor paid-in capital in excess of par		1,095,369,000
Accumulated deficit		(2,219,106,000)
Total stockholders' equity		540,117,000
Total liabilities and stockholders' equity		3,622,419,000
Accounts payable and accrued liabilities		102,793,000
Current maturities of long-term debt		73,199,000
Operating lease liabilities		757,000
Long-term debt, net of current portion		42,610,000
Asset retirement obligations		180,408,000
Operating lease liabilities		515,000
Other liabilities		3,540,000
Liabilities subject to compromise		2,823,506,000
Deferred tax liabilities, net		414,100,000
Cash and cash equivalents		45,585,000
Restricted cash		10,662,000
Accrued production receivable		112,832,000
Trade and other receivables, net		36,221,000
Derivative assets		32,635,000
Other current assets		12,429,000
Total current assets		250,364,000
Proved properties		782,233,000
Unevaluated properties		111,983,000
CO2 properties		187,346,000
Pipelines		132,618,000
Other property and equipment		97,413,000
Less accumulated depletion, depreciation, amortization and impairment		0
Net property and equipment		1,311,593,000
Operating lease right-of-use assets		1,843,000
Derivative assets		501,000
Intangible assets, net		100,083,000
Other assets		87,023,000
Total assets		1,751,407,000
Accounts payable and accrued liabilities		174,320,000
Oil and gas production payable		56,077,000
Derivative liabilities		8,613,000
Current maturities of long-term debt		73,563,000
Operating lease liabilities		728,000
Total current liabilities		313,301,000
Long-term debt, net of current portion		157,459,000
Asset retirement obligations		158,438,000
Derivative liabilities		295,000
Deferred tax liabilities, net		3,831,000
Operating lease liabilities		525,000
Other liabilities		22,139,000
Total long-term liabilities not subject to compromise		342,687,000
Successor common stock		50,000
Successor paid-in capital in excess of par		1,095,369,000
Equity value		1,095,419,000
Total liabilities and stockholders' equity		1,751,407,000
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents		(27,787,000)
Restricted cash		10,662,000
Other current assets		(539,000)
Total current assets		(17,664,000)
Other assets		8,241,000
Total assets		(9,423,000)
Oil and gas production payable		16,705,000
Total current liabilities		193,454,000
Total long-term liabilities not subject to compromise		645,024,000
Predecessor common stock		(510,000)
Predecessor paid-in capital in excess of par		(2,764,915,000)
Predecessor treasury stock, at cost		6,202,000
Successor common stock		50,000
Successor paid-in capital in excess of par		1,095,369,000
Accumulated deficit		3,639,409,000
Total stockholders' equity		1,975,605,000
Total liabilities and stockholders' equity		(9,423,000)
Current maturities of long-term debt		73,199,000
Operating lease liabilities		757,000
Long-term debt, net of current portion		42,610,000
Asset retirement obligations		180,408,000
Deferred tax liabilities, net		417,951,000
Operating lease liabilities		515,000
Other liabilities		3,540,000
Liabilities subject to compromise		(2,823,506,000)
Fresh Start Adjustments
Fresh-Start Adjustment [Line Items]
Proved properties		(10,941,313,000)
Unevaluated properties		(538,570,000)
CO2 properties		(1,011,169,000)
Pipelines		(2,207,246,000)
Other property and equipment		(104,152,000)
Less accumulated depletion, depreciation, amortization and impairment		12,864,141,000
Net property and equipment		(1,938,309,000)
Operating lease right-of-use assets		69,000
Intangible assets, net		79,678,000
Other assets		(3,027,000)
Total assets		(1,861,589,000)
Accounts payable and accrued liabilities		3,738,000
Current maturities of long-term debt		364,000
Operating lease liabilities		(29,000)
Total current liabilities		4,073,000
Long-term debt, net of current portion		(25,151,000)
Asset retirement obligations		(24,697,000)
Deferred tax liabilities, net		(414,120,000)
Operating lease liabilities		10,000
Other liabilities		18,599,000
Total long-term liabilities not subject to compromise		(445,359,000)
Accumulated deficit		(1,420,303,000)
Total stockholders' equity		(1,420,303,000)
Total liabilities and stockholders' equity		$ (1,861,589,000)

Fresh Start Accounting (Net Cas

Fresh Start Accounting (Net Cash Payments) (Details 4) $ in Thousands	9 Months Ended
	Sep. 18, 2020USD ($)
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)

Fresh Start Accounting (Account

Fresh Start Accounting (Accounts Payable and Accrued Liabilities) (Details 5) $ in Thousands	Sep. 18, 2020USD ($)
Reorganizations [Abstract]
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
Accounts payable and accrued liabilities	$ 102,793

Fresh Start Accounting (Liabili

Fresh Start Accounting (Liabilities Subject to Compromise) (Details 6) $ in Thousands	Sep. 18, 2020USD ($)
Reorganizations [Abstract]
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
Current maturities of long-term debt	73,199
Accounts payable and accrued liabilities	101,431
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
Deferred tax liabilities	289,389
Operating lease liabilities, long term	515
Other long-term liabilities	3,540
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

Fresh Start Accounting (Success

Fresh Start Accounting (Successor's Common Stock and Additional Paid-In Capital) (Details 7) $ in Thousands	Sep. 18, 2020USD ($)
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)
Change in Successor additional paid-in capital	$ 1,095,369

Fresh Start Accounting (Accumul

Fresh Start Accounting (Accumulated Deficit Adjustments) (Details 8) $ in Thousands	Sep. 18, 2020USD ($)
Reorganizations [Abstract]
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	$ 3,639,409

Fresh Start Accounting (Fair Va

Fresh Start Accounting (Fair Value Other Assets) (Details 9) $ in Thousands	Sep. 18, 2020USD ($)
Fresh-Start Adjustment [Line Items]
Fair value adjustment for CO2 and oil pipeline line-fill	$ (3,698)
Fresh value adjustments for escrow accounts	671
Fresh Start Adjustments
Fresh-Start Adjustment [Line Items]
Fair value adjustments to other assets	$ (3,027)

Fresh Start Accounting (Fair _2

Fresh Start Accounting (Fair Value Accounts Payable and Accrued Liabilities) (Details 10) $ in Thousands	Sep. 18, 2020USD ($)
Fresh-Start Adjustment [Line Items]
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]
Fair value adjustments to accounts payable and accrued liabilities	$ 3,738

Fresh Start Accounting (Debt Ad

Fresh Start Accounting (Debt Adjustments) (Details 11) $ in Thousands	Sep. 18, 2020USD ($)
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)

Fresh Start Accounting (Details

Fresh Start Accounting (Details Textuals) - USD ($) $ / shares in Units, $ in Thousands	Sep. 30, 2020	Sep. 18, 2020	Sep. 18, 2020	Dec. 31, 2020	Sep. 18, 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
Cash outflow related to payment of professional service provider fees and success fees					12,700
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
Decrease to deferred tax liabilities related to fresh start accounting adjustments		414,100	414,100		414,100
Stockholders' Equity, Period Increase (Decrease)		4,600			(5,331)
Minimum
Reorganization Value [Line Items]
Enterprise value		1,100,000	1,100,000		1,100,000
Useful life of intangible CO2 contracts	7 years			7 years
Minimum | Pipelines
Reorganization Value [Line Items]
Useful life	20 years			20 years
Maximum
Reorganization Value [Line Items]
Enterprise value		1,500,000	1,500,000		1,500,000
Useful life of intangible CO2 contracts	14 years			14 years
Maximum | Pipelines
Reorganization Value [Line Items]
Useful life	43 years			43 years
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

Predecessor Divestiture (Detail

Predecessor Divestiture (Details Textuals) - USD ($)	Mar. 04, 2020	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Text Block [Abstract]
Net proceeds from sales of oil and natural gas properties and equipment	$ 40,000,000	$ 938,000	$ 41,322,000	$ 10,196,000	$ 7,762,000
Gain (loss) on disposition of oil and natural gas properties	$ 0

Revenue Recognition (Disaggrega

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, 2019	Dec. 31, 2018
Disaggregation of Revenue
Revenues	$ 215,903	$ 521,693	$ 1,260,360	$ 1,455,655
Oil sales
Disaggregation of Revenue
Revenues	199,769	489,251	1,205,083	1,412,358
Natural gas sales
Disaggregation of Revenue
Revenues	1,339	2,850	6,937	10,231
CO2 sales and transportation fees
Disaggregation of Revenue
Revenues	9,419	21,049	34,142	31,145
Oil marketing revenues
Disaggregation of Revenue
Revenues	$ 5,376	$ 8,543	$ 14,198	$ 1,921

Leases (Supplemental Balance Sh

Leases (Supplemental Balance Sheet Information Related to Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases, Operating [Abstract]
Operating lease right-of-use assets	$ 20,342	$ 34,099
Operating lease liabilities - current	1,350	6,901
Operating lease liabilities - long-term	19,460	41,932
Total operating lease liabilities	$ 20,810	$ 48,833

Leases (Lease Term and Discount

Leases (Lease Term and Discount Rate) (Details 1)	Dec. 31, 2020Rate	Dec. 31, 2019Rate
Leases [Abstract]
Weighted average remaining lease term	6 years 3 months 18 days	5 years 8 months 12 days
Weighted average discount rate	5.60%	6.70%

Leases (Lease Operating Costs)

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, 2019
Lease Cost [Line Items]
Operating lease cost	$ 1,044	$ 5,934	$ 8,987
Lease cost
Amortization of right-of-use assets	3	9	1,188
Interest on lease liabilities	1	3	40
Total finance lease cost	4	12	1,228
Sublease income	100	2,584	4,127
General and administrative expenses
Lease Cost [Line Items]
Operating lease cost	872	5,683	8,924
Lease operating expenses
Lease Cost [Line Items]
Operating lease cost	158	214	58
CO2 operating and discovery expenses
Lease Cost [Line Items]
Operating lease cost	$ 14	$ 37	$ 5

Leases (Supplemental Cash Flow

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, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 341	$ 7,341	$ 10,995
Operating cash flows from interest on finance leases	1	3	40
Financing cash flows from finance leases	78	10	1,275
Right-of-use assets obtained in exchange for lease obligations
Operating leases	19,902	1,049	415
Finance leases	$ 0	$ 162	$ 0

Leases (Maturities of Lease Lia

Leases (Maturities of Lease Liabilities) (Details 4) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
2021	$ 2,496
2022	4,149
2023	4,135
2024	4,111
2025	4,149
Thereafter	6,263
Total minimum lease payments	25,303
Less: Amount representing interest	(4,493)
Present value of minimum lease liabilities	$ 20,810	$ 48,833

Leases (Details Textuals)

Leases (Details Textuals) - Maximum	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Remaining lease term	7 years
Land
Lessee, Lease, Description [Line Items]
Remaining lease term	49 years

Asset Retirement Obligations (R

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, 2019
Asset Retirement Obligation Roll Forward [Roll Forward]
Beginning asset retirement obligations		$ 163,368	$ 181,760	$ 176,585
Liabilities incurred and assumed during period		738	736	4,354
Revisions in estimated retirement obligations		22,660	3,592	9,206
Liabilities settled and sold during period		(3,439)	(10,041)	(24,342)
Accretion expense		2,954	11,329	15,957
Fresh start accounting adjustment		0	(24,008)	0
Ending asset retirement obligations		186,281	163,368	181,760
Less: current asset retirement obligations	[1]	(6,943)	(4,930)	(4,652)
Long-term asset retirement obligations		$ 179,338	$ 158,438	$ 177,108
[1]	Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details Textuals) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Balance in escrow accounts	$ 55.2	$ 53.4

Unevaluated Property (Summary o

Unevaluated Property (Summary of Unevaluated Properties Excluded from Amortization) (Details) - USD ($)	Sep. 18, 2020		Dec. 31, 2020	Dec. 31, 2019
Summary of unevaluated properties excluded from oil and natural gas properties being amortized
Property acquisition costs	$ 84,019,000	[1]	$ 0
Exploration and development	0		46,000
Capitalized interest	0		1,239,000
Total	$ 84,019,000	[1]	1,285,000
Property acquisition costs			84,019,000
Exploration and development			46,000
Capitalized interest			1,239,000
Total			$ 85,304,000	$ 872,910,000
[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, 2020.

Unevaluated Property (Details T

Unevaluated Property (Details Textuals)	12 Months Ended
	Dec. 31, 2020
Minimum
Capitalized Costs of Unproved Properties Excluded from Amortization
Anticipated timing of inclusion of costs in amortization calculation	5 years
Maximum
Capitalized Costs of Unproved Properties Excluded from Amortization
Anticipated timing of inclusion of costs in amortization calculation	10 years

Long-Term Debt (Components of L

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Jun. 30, 2019
Debt Instrument [Line Items]
Pipeline financings	$ 68,008	$ 167,439
Total debt principal balance	138,008	2,281,726
Debt discount	0	(101,767)
Future interest payable	0	164,914
Debt issuance costs	0	(10,009)
Total debt, net of debt issuance costs and discount	138,008	2,334,864
Less: current maturities of long-term debt	(68,008)	(102,294)
Long-term debt and capital lease obligations	70,000	2,232,570
Successor Senior Secured Bank Credit Agreement
Debt Instrument [Line Items]
Outstanding borrowings on bank credit facility	70,000	0
Predecessor Senior Secured Bank Credit Agreement
Debt Instrument [Line Items]
Outstanding borrowings on bank credit facility	0	0
9% Senior Secured Second Lien Notes due 2021
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 614,919
Stated interest rate percentage		9.00%
9 1/4% Senior Secured Second Lien Notes due 2022
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 455,668
Stated interest rate percentage		9.25%
7 3/4% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 531,821
Debt discount			$ (22,600)
Stated interest rate percentage		7.75%
7 1/2% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 20,641
Stated interest rate percentage		7.50%
6 3/8% Convertible Senior Notes due 2024
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 245,548
Debt discount			$ (79,900)
Stated interest rate percentage		6.375%
6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 51,304
Stated interest rate percentage		6.375%
5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Outstanding debt principal balance	0	$ 58,426
Stated interest rate percentage		5.50%
4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Outstanding debt principal balance	$ 0	$ 135,960
Stated interest rate percentage		4.625%

Long-Term Debt (Debt Maturity S

Long-Term Debt (Debt Maturity Schedule) (Details 1) $ in Thousands	Dec. 31, 2020USD ($)
Indebtedness repayment schedule
2021	$ 68,008
2022	0
2023	0
2024	70,000
2025	0
Thereafter	0
Total indebtedness	$ 138,008

Long-Term Debt (Details Textual

Long-Term Debt (Details Textuals)	Oct. 31, 2020USD ($)	Sep. 18, 2020USD ($)	Mar. 31, 2020USD ($)	Jul. 31, 2019USD ($)	Jun. 30, 2019USD ($)	May 31, 2018shares	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)shares	Dec. 31, 2019USD ($)shares	Sep. 18, 2020USD ($)shares	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Aug. 07, 2020USD ($)	Sep. 30, 2019USD ($)
Debt Instrument [Line Items]
Interest in guarantor subsidiaries							100.00%					100.00%
Principal amount of debt cancelled		$ 2,100,000,000
Lease period included in long-term transportation service agreement												20 years
Letters of credit outstanding under DIP Facility															$ 41,300,000
Shares issued upon conversion of notes | shares						55,200,000			7,400,000
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		155,998,000	$ 0
Cash paid for debt repurchases or exchanges					$ 120,000,000			$ 5,300,000		$ 11,200,000
Debt discount							0			101,767,000		$ 0	101,767,000
Unamortized debt issuance costs							8,400,000			$ 14,000,000		8,400,000	$ 14,000,000
Senior Secured Bank Credit Facility [Abstract]
Borrowing base							575,000,000					575,000,000
Lender commitments		$ 575,000,000					$ 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%					25.00%
Floor interest rate							1.00%
Weighted average interest rate							4.00%
Commitment fee percentage							0.50%
Common Stock
Debt Instrument [Line Items]
Shares issued upon conversion of notes | shares											7,372,250			55,249,955
Issuance of new shares, shares | shares										38,300,000	49,999,999		36,297,217
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					$ 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					$ 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%					5.00%
Current ratio requirement							1
Minimum | Dividend or Other Restricted Payment
Senior Secured Bank Credit Facility [Abstract]
Borrowing base availability requirement							20.00%					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) | 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
7 3/4% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Debt discount					22,600,000
6 3/8% Convertible Senior Notes due 2024
Debt Instrument [Line Items]
Debt principal of notes converted									$ 19,900,000
Face value of notes					245,500,000
Debt discount					79,900,000
6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Amount of debt exchanged					152,200,000
5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Debt repurchases, face amount										$ 25,300,000			$ 25,300,000			$ 11,000,000
Amount of debt exchanged					219,900,000
4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Debt repurchases, face amount										$ 75,700,000			75,700,000
Amount of debt exchanged					96,300,000
Senior Subordinated Notes
Debt Instrument [Line Items]
Amount of debt exchanged					468,400,000
Notes Repurchases
Debt Instrument [Line Items]
Gain on debt extinguishment													55,500,000
Portion Of Exchange Related To Senior Secured Notes
Debt Instrument [Line Items]
Gain on debt extinguishment					0
Portion Of Exchange Related To Senior Secured Notes | 7 3/4% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Face value of notes				$ 3,800,000	425,400,000
Unamortized debt issuance costs					6,900,000
Portion Of Exchange Related To Senior Secured Notes | 7 1/2% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Amount of debt exchanged				$ 4,000,000	425,400,000
Notes Exchange
Debt Instrument [Line Items]
Gain on debt extinguishment													$ 100,500,000
Notes Exchange | 7 3/4% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Face value of notes					$ 102,600,000

Income Taxes (Income Tax Provis

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, 2019	Dec. 31, 2018
Current income tax expense (benefit)
Federal	$ 0	$ (6,407)	$ 2,645	$ (17,885)
State	30	(853)	1,236	1,884
Total current income tax expense (benefit)	30	(7,260)	3,881	(16,001)
Deferred income tax expense (benefit)
Federal	0	(319,011)	89,950	93,395
State	(2,556)	(89,858)	10,521	9,839
Total deferred income tax expense (benefit)	(2,556)	(408,869)	100,471	103,234
Total income tax expense (benefit)	$ (2,526)	$ (416,129)	$ 104,352	$ 87,233

Income Taxes (Summary of Change

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, 2019	Dec. 31, 2018
Valuation Allowance [Line Items]
Beginning balance	$ 129,840	$ 77,215	$ 51,093	$ 51,134
Charges	2,269	77,138	26,122	0
Deductions	(2,701)	(24,513)	0	(41)
Ending balance	$ 129,408	$ 129,840	$ 77,215	$ 51,093

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 2) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets
Property and equipment	$ 59,207	$ 0
Loss and tax credit carryforwards - state	55,979	52,917
Accrued liabilities and other reserves	15,632	29,788
Derivative contracts	13,090	0
Lease liabilities	6,354	10,841
Business interest expense carryforward	0	24,513
Business credit carryforwards	0	71,555
Unrecognized gain and original issue discount on debt exchange	0	41,556
Other	4,092	15,664
Valuation allowances	(129,408)	(77,215)
Total deferred tax assets	24,946	169,619
Deferred tax liabilities
CO2 and other contracts	(20,030)	0
Operating lease right-of-use assets	(6,190)	(7,780)
Property and equipment	0	(569,254)
Derivative contracts	0	(1,120)
Other	0	(1,695)
Total deferred tax liabilities	(26,220)	(579,849)
Total net deferred tax liability	$ (1,274)	$ (410,230)

Income Taxes (Schedule of Effec

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, 2019	Dec. 31, 2018
Effective Income Tax Rate Reconciliation, Amount
Income tax provision calculated using the federal statutory income tax rate	$ (11,169)	$ (388,228)	$ 67,475	$ 86,086
State income taxes, net of federal income tax benefit	(2,532)	(86,937)	7,435	11,968
Tax shortfall (windfall) on stock-based compensation deduction	0	(1,502)	1,912	(1,565)
Valuation allowance	9,653	19,344	26,122	(42)
Tax attributes reduction - net of CODI exclusion	0	31,667	0	0
Enhanced oil recovery credits generated	0	0	0	(10,818)
Other	1,522	9,527	1,408	1,604
Total income tax expense (benefit)	$ (2,526)	$ (416,129)	$ 104,352	$ 87,233

Income Taxes (Details Textuals)

Income Taxes (Details Textuals) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Valuation Allowance [Line Items]
Valuation allowance	$ 129,408,000	$ 77,215,000
Federal net operating loss carryforwards	0
Business interest expense carryforward	0	24,513,000
Business credit carryforwards	0	71,555,000
Alternative minimum tax credits	600,000
Loss and tax credit carryforwards - state	55,979,000	$ 52,917,000
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	75,100,000
Valuation allowance	$ 75,100,000

Stockholders' Equity (Registrat

Stockholders' Equity (Registration Rights Agreement) (Details Textuals) - Minimum - USD ($)	3 Months Ended
	Dec. 31, 2020	Sep. 18, 2020
Stock ownership percentage threshold for holders covered under Registration Rights Agreement		4.00%
Proceeds from issuance of common stock	$ 25,000,000
Percentage of registrable securities	20.00%

Stockholders' Equity (Details T

Stockholders' Equity (Details Textuals 2) - 401(k) Plan - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Contribution Benefit Plans Disclosures [Line Items]
Employer contribution rate			100.00%
Employer's matching contributions	$ 1.1	$ 4.4		$ 6.3	$ 6.2
Maximum
Defined Contribution Benefit Plans Disclosures [Line Items]
Employee contribution rate			6.00%

Stock Compensation (Schedule of

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, 2019	Dec. 31, 2018
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Abstract]
Stock-based compensation expense included in G&A	$ 8,212	$ 4,111	$ 12,470	$ 11,951
Stock-based compensation capitalized	695	1,660	4,018	3,487
Total cost of stock-based compensation arrangements	8,907	5,771	16,488	15,438
Income tax benefit recognized for stock-based compensation arrangements	$ 2,053	$ 1,028	$ 3,118	$ 2,988

Stock Compensation (Summary of

Stock Compensation (Summary of Restricted Stock Unit) (Details 2) - Restricted Stock Units	3 Months Ended
	Dec. 31, 2020$ / sharesshares
Stock Compensation
Nonvested at beginning of period | shares	0
Weighted average grant-date fair value, beginning of period | $ / shares	$ 0
Granted | shares	1,219,867
Weighted average grant-date fair value, granted | $ / shares	$ 24.67
Vested | shares	0
Weighted average grant-date fair value, vested | $ / shares	$ 0
Forfeited | shares	0
Weighted average grant-date fair value, forfeited | $ / shares	$ 0
Nonvested at end of period | shares	1,219,867
Weighted average grant-date fair value, end of period | $ / shares	$ 24.67

Stock Compensation (PSU Perform

Stock Compensation (PSU Performance and Vesting Terms ) (Details 3) - Performance Share Units	3 Months Ended
	Dec. 31, 2020$ / shares
Tier 0
Stock Compensation
Cumulative percentage of PSUs that become vested	0.00%
Tier 1
Stock Compensation
Cumulative percentage of PSUs that become vested	25.00%
Tier 2
Stock Compensation
Cumulative percentage of PSUs that become vested	50.00%
Tier 3
Stock Compensation
Cumulative percentage of PSUs that become vested	75.00%
Tier 4
Stock Compensation
Cumulative percentage of PSUs that become vested	100.00%
Minimum | Tier 1
Stock Compensation
Stock price threshold per share	$ 18.75
Minimum | Tier 2
Stock Compensation
Stock price threshold per share	21
Minimum | Tier 3
Stock Compensation
Stock price threshold per share	23.25
Minimum | Tier 4
Stock Compensation
Stock price threshold per share	25.75
Maximum | Tier 0
Stock Compensation
Stock price threshold per share	$ 18.74

Stock Compensation (PSU Award V

Stock Compensation (PSU Award Valuation Assumptions) (Details 4) - Performance Share Units	3 Months Ended
	Dec. 31, 2020$ / shares
Stock Compensation
Weighted average grant-date fair value, granted	$ 24.19
Risk-free interest rate	0.21%
Expected life	2 months 23 days
Expected volatility	110.00%
Dividend yield	0.00%

Stock Compensation (Summary o_2

Stock Compensation (Summary of PSU Activity) (Details 5) - Performance Share Units	3 Months Ended
	Dec. 31, 2020$ / sharesshares
Stock Compensation
Nonvested at beginning of period | shares	0
Weighted average grant-date fair value, beginning of period | $ / shares	$ 0
Granted | shares	1,021,222
Weighted average grant-date fair value, granted | $ / shares	$ 24.19
Vested | shares	0
Weighted average grant-date fair value, vested | $ / shares	$ 0
Forfeited | shares	0
Weighted average grant-date fair value, forfeited | $ / shares	$ 0
Nonvested at end of period | shares	1,021,222
Weighted average grant-date fair value, end of period | $ / shares	$ 24.19

Stock Compensation (Summary o_3

Stock Compensation (Summary of SARs Activity) (Details 6) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 18, 2020USD ($)$ / sharesshares
Share-based Payment Arrangement, Disclosure [Abstract]
Number of awards outstanding at December 31, 2019 (Predecessor) | shares	1,981,156
Weighted average exercise price, December 31, 2019 (Predecessor) | $ / shares	$ 9.12
Number of awards, granted | shares	0
Weighted average exercise price, granted | $ / shares	$ 0
Number of awards, exercised | shares	0
Weighted average exercise price, exercised | $ / shares	$ 0
Number of awards, expired | shares	(580,087)
Weighted average exercise price, expired | $ / shares	$ 12.38
Number of awards, cancelled | shares	(1,401,069)
Weighted average exercise price, cancelled | $ / shares	$ 7.77
Number of awards outstanding at September 18, 2020 (Predecessor) | shares	0
Weighted average exercise price, September 18, 2020 (Predecessor) | $ / shares	$ 0
Weighted average remaining contractual life of outstanding SARs	0 years
Aggregate intrinsic value of SARs outstanding | $	$ 0
Exercisable awards at end of period | shares	0
Weighted average price, exercisable at end of period | $ / shares	$ 0
Weighted average remaining contractual life of exercisable SARs	0 years
Aggregate intrinsic value of exercisable SARs | $	$ 0

Stock Compensation (Summary o_4

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	Dec. 31, 2018
Restricted Stock
Stock Compensation
Fair value of restricted stock vested	$ 707	$ 5,743	$ 23,060

Stock Compensation (Summary o_5

Stock Compensation (Summary of Restricted Stock) (Details 8) - Restricted Stock	9 Months Ended
	Sep. 18, 2020$ / sharesshares
Nonvested Restricted Stock Outstanding [Line Items]
Nonvested at beginning of period | shares	12,407,436
Weighted average grant-date fair value, beginning of period | $ / shares	$ 1.91
Granted | shares	0
Weighted average grant-date fair value, granted | $ / shares	$ 0
Vested | shares	(2,743,473)
Weighted average grant-date fair value, vested | $ / shares	$ 2.10
Cancelled | shares	(9,663,963)
Weighted average grant-date fair value, cancelled | $ / shares	$ 1.85
Nonvested at end of period | shares	0
Weighted average grant-date fair value, end of period | $ / shares	$ 0

Stock Compensation (TSR Award A

Stock Compensation (TSR Award Assumptions) (Details 9) - Performance-Based TSR Awards - $ / shares	9 Months Ended	12 Months Ended
	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Stock Compensation
Weighted average fair value of Performance-Based TSR Awards granted	$ 0.15	$ 1.95	$ 2.29
Risk-free interest rate	0.27%	2.27%	2.37%
Expected life	3 years	3 years	3 years
Expected volatility	89.60%	77.20%	102.90%
Dividend yield	0.00%	0.00%	0.00%

Stock Compensation (Summary o_6

Stock Compensation (Summary of Performance Based Equity Awards) (Details 10) - $ / shares		9 Months Ended	12 Months Ended
		Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Performance-Based Operational Awards
Stock Compensation
Nonvested at beginning of period		1,838,584
Weighted average grant-date fair value, beginning of period		$ 2.27
Granted		0
Weighted average grant-date fair value, granted		$ 0
Vested		0
Weighted average grant-date fair value, vested		$ 0
Forfeited		(102,469)
Weighted average grant-date fair value, forfeited		$ 2.28
Cancelled		(1,736,115)
Weighted average grant-date fair value, cancelled		$ 2.27
Nonvested at end of period		0	1,838,584
Weighted average grant-date fair value, end of period		$ 0	$ 2.27
Performance-Based TSR Awards
Stock Compensation
Nonvested at beginning of period		4,475,998
Weighted average grant-date fair value, beginning of period		$ 2.65
Granted	[1]	3,041,774
Weighted average grant-date fair value, granted		$ 0.15	$ 1.95	$ 2.29
Vested	[2]	(742,996)
Weighted average grant-date fair value, vested		$ 3.42
Forfeited		(385,183)
Weighted average grant-date fair value, forfeited		$ 1.26
Cancelled		(6,389,593)
Weighted average grant-date fair value, cancelled		$ 1.23
Nonvested at end of period		0	4,475,998
Weighted average grant-date fair value, end of period		$ 0	$ 2.65
Performance-Based Equity Awards
Stock Compensation
Vested		(438,363)
Payout percentage		59.00%
Performance-Based Equity Awards | Minimum
Stock Compensation
Payout percentage		0.00%
Performance-Based Equity Awards | Maximum
Stock Compensation
Payout percentage		200.00%
[1]	Amounts granted reflect the number of performance units granted. The actual payout of the shares were between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of stock, in order to conserve available shares.
[2]	During 2020, the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 59% of target for each vested TSR performance-based award, representing 438,363 aggregate shares of Predecessor common stock issued. There were no vestings related to the Predecessor’s Operational performance-based awards during 2020.

Stock Compensation (Summary o_7

Stock Compensation (Summary of Vesting Date Fair Value of Awards) (Details 11) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 18, 2020	Dec. 31, 2019	Dec. 31, 2018
Performance-Based Operational Awards
Stock Compensation
Vesting date fair value	$ 0	$ 0	$ 595
Performance-Based TSR Awards
Stock Compensation
Vesting date fair value	$ 79	$ 2,783	$ 542

Stock Compensation (Details Tex

Stock Compensation (Details Textual)	1 Months Ended		3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2020USD ($)shares	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)shares	Sep. 18, 2020USD ($)shares	Sep. 18, 2020USD ($)shares	Dec. 31, 2020USD ($)shares	Dec. 31, 2019shares	Dec. 31, 2018USD ($)shares
Stock Compensation Plans (Textuals)
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
Number of awards exercised | shares					0
Percentage based on continued employment
Stock Compensation Plans (Textuals)
Repayment percentage		50.00%
Percentage based on metrics
Stock Compensation Plans (Textuals)
Repayment percentage		50.00%
Restricted Stock Units
Stock Compensation Plans (Textuals)
Total grants | shares			1,219,867
Total compensation cost to be recognized in future periods | $	$ 29,300,000		$ 29,300,000			$ 29,300,000
Weighted average period over which remaining cost will be recognized			2 years 10 months 24 days
Performance Share Units
Stock Compensation Plans (Textuals)
Total grants | shares			1,021,222
Award vesting or performance period			3 years
Total compensation cost to be recognized in future periods | $	$ 16,600,000		$ 16,600,000			$ 16,600,000
Weighted average period over which remaining cost will be recognized			2 months 12 days
Stock Appreciation Rights (SARs)
Stock Compensation Plans (Textuals)
Award vesting or performance period					3 years
Total compensation cost to be recognized in future periods | $								$ 0
SARs expiration period					7 years
Grant-date fair value of SARs vested | $								$ 1,100,000
Number of awards exercised | shares					0		0	0
Restricted Stock
Stock Compensation Plans (Textuals)
Total grants | shares					0
Award vesting or performance period					3 years	3 years
Total compensation cost to be recognized in future periods | $				$ 0	$ 0
Performance-based equity awards
Stock Compensation Plans (Textuals)
Award vesting or performance period					3 years 3 months
Payout percentage					59.00%
Performance-based equity awards | Minimum
Stock Compensation Plans (Textuals)
Award vesting or performance period						1 year 3 months
Payout percentage					0.00%
Performance-based equity awards | Maximum
Stock Compensation Plans (Textuals)
Payout percentage					200.00%
2020 Omnibus Stock and Incentive Plan
Stock Compensation Plans (Textuals)
Maximum number of common stock shares authorized for issuance under Plan | shares	6,200,000		6,200,000			6,200,000
Total grants | shares	2,200,000
Shares available for future awards | shares	4,000,000		4,000,000			4,000,000
2004 Omnibus Stock and Incentive Plan
Stock Compensation Plans (Textuals)
Maximum number of common stock shares authorized for issuance under Plan | shares				61,400,000	61,400,000

Commodity Derivative Contract_2

Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - NYMEX	Dec. 31, 2020bbl / d$ / Barrel
Swap | 2021
Derivative [Line Items]
Volume per day | bbl / d	26,000
Weighted average swap price	42.54
Swap | 2021 | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	38.68
Swap | 2021 | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	47.69
Swap | 2022 | Q1-Q2
Derivative [Line Items]
Volume per day | bbl / d	8,500
Weighted average swap price	43.55
Swap | 2022 | Q1-Q2 | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	42.65
Swap | 2022 | Q1-Q2 | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	45.50
Collar | 2021
Derivative [Line Items]
Volume per day | bbl / d	3,000
Weighted average floor price	45
Weighted average ceiling price	50.95
Collar | 2021 | Minimum
Derivative [Line Items]
Derivative, Floor Price	45
Collar | 2021 | Maximum
Derivative [Line Items]
Derivative, Cap Price	51.30

Commodity Derivative Contract_3

Commodity Derivative Contracts (Details Textuals) - Crude Oil [Member] - Minimum	3 Months Ended
	Dec. 31, 2020
Initial measurement period (Aug. 1, 2020 - July 31, 2021)
Derivative [Line Items]
Required hedge percentage	65.00%
Subsequent measurement period (August 1, 2021 - July 31, 2022)
Derivative [Line Items]
Required hedge percentage	35.00%

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Hierarchy) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	$ 187	$ 11,936
Total Assets	187	11,936
Oil derivative contracts - current liabilities	(53,865)	(8,346)
Oil derivative contracts - long-term liabilities	(5,087)	0
Total Liabilities	(58,952)	(8,346)
Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	0	0
Total Assets	0	0
Oil derivative contracts - current liabilities	0	0
Oil derivative contracts - long-term liabilities	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	8,503
Total Assets	187	8,503
Oil derivative contracts - current liabilities	(53,865)	(6,522)
Oil derivative contracts - long-term liabilities	(5,087)
Total Liabilities	(58,952)	(6,522)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	0	3,433
Total Assets	0	3,433
Oil derivative contracts - current liabilities	0	(1,824)
Oil derivative contracts - long-term liabilities	0
Total Liabilities	$ 0	$ (1,824)

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Fair Value Measurements) (Details 2) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of period	$ 0	$ 1,609	$ 13,624
Transfers out of Level 3	0	(1,609)	0
Fair value adjustments on commodity derivatives	0	0	(8,205)
Receipt on settlements of commodity derivatives	0	0	(3,810)
Fair value of Level 3 instruments, end of period	0	0	1,609
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date	$ 0	$ 0	$ (556)

Fair Value Measurements (Detail

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	Sep. 18, 2020	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair value of debt		$ 70	$ 1,833.1
Principal amount of debt cancelled	$ 2,100

Commitments and Contingencies (

Commitments and Contingencies (Details Textuals)	Dec. 31, 2020USD ($)MMcf / d$ / BarrelMMcf	Dec. 23, 2020USD ($)	Dec. 31, 2020USD ($)MMcf / dMMcf
Commitments and Contingencies Disclosure [Abstract]
Material tax assessments	$ 0		$ 0
Industrial-sourced CO2 purchase contracts
Long-term Purchase Commitment [Line Items]
Term of long-term purchase commitments			8 years
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel	60
Industrial-sourced CO2 purchase contracts | Minimum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2			$ 15,000,000
Industrial-sourced CO2 purchase contracts | Maximum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2			$ 23,000,000
Industrial CO2 customer contracts
Long-term Purchase Commitment [Line Items]
Significant supply commitment remaining volume committed (MMcf) | MMcf	673,000		673,000
Term of long-term supply arrangement			14 years
Significant supply commitment yearly maximum volume required (MMcf/d) | MMcf / d	276		276
Helium Supply Arrangement
Long-term Purchase Commitment [Line Items]
Term of long-term supply arrangement			20 years
Litigation settlement payment		$ 52,100,000
Processing fee related to overriding royalty interest in CO2 | Minimum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2			$ 8,000,000
Processing fee related to overriding royalty interest in CO2 | Maximum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2			$ 11,000,000

Additional Balance Sheet Deta_3

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, 2019	Dec. 31, 2018
Valuation Allowance [Line Items]
Beginning balance	$ 22,146	$ 17,137	$ 17,070	$ 229
Provision for doubtful accounts	1,060	5,297	68	16,911
Write-offs	0	(288)	(1)	(70)
Ending balance	$ 23,206	$ 22,146	$ 17,137	$ 17,070

Additional Balance Sheet Deta_4

Additional Balance Sheet Details (Details 2) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Text Block [Abstract]
Accrued general and administrative expenses	$ 21,825	$ 21,838
Accrued lease operating expenses	21,294	26,686
Accounts payable	18,629	29,077
Taxes payable	17,221	21,274
Accrued compensation	7,512	36,366
Accrued exploration and development costs	1,861	7,811
Accrued interest	1,833	25,253
Other	22,496	15,527
Total	$ 112,671	$ 183,832

Supplemental Cash Flow Inform_3

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, 2019	Dec. 31, 2018
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, expensed	$ 813	$ 29,357	$ 72,842	$ 50,076
Cash paid for interest, capitalized	1,261	22,885	36,671	37,079
Cash paid for interest, treated as a reduction of debt	0	46,417	85,303	79,606
Cash paid for income taxes	0	453	2,361	492
Cash received from income tax refunds	10,457	1,932	9,820	8,280
Noncash investing and financing activities
Increase in asset retirement obligations	23,398	4,328	13,560	4,499
Increase (decrease) in liabilities for capital expenditures	1,867	(12,809)	(17,740)	14,600
Conversion of convertible senior notes into common stock	$ 0	$ 11,501	$ 0	$ 162,004

Subsequent Event (Details Textu

Subsequent Event (Details Textuals) $ in Millions	Mar. 03, 2021USD ($)
Subsequent Event
Subsequent Event [Line Items]
Acquisition cash purchase price	$ 12