Denbury (DNRWW) 10-K 23 Feb 23 2022 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	Jan. 31, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-12935
Entity Registrant Name	DENBURY INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-0467835
Entity Address, Address Line One	5851 Legacy Circle,
Entity Address, City or Town	Plano,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75024
City Area Code	(972)
Local Phone Number	673-2000
Title of 12(b) Security	Common Stock $.001 Par Value
Trading Symbol	DEN
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Auditor Attestation Flag	true
Entity Shell Company	false
Entity Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 3,048,881,728
Entity Common Stock, Shares Outstanding		49,839,666
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Document: Incorporated as to: 1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held June 1, 2023. 1. Part III, Items 10, 11, 12, 13, 14
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0000945764
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Dallas, TX
Auditor Firm ID	238

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Firm ID	238
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Dallas, TX

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 521	$ 3,671
Accrued production receivable	144,277	143,365
Trade and other receivables, net	27,343	19,270
Derivative assets	15,517	0
Prepaids	18,572	9,099
Total current assets	206,230	175,405
Oil and natural gas properties (using full cost accounting)
Proved properties	1,414,779	1,109,011
Unevaluated properties	240,435	112,169
CO2 properties	190,985	183,369
Pipelines	220,125	224,394
CCUS storage sites and related assets	64,971	0
Other property and equipment	107,133	93,950
Less accumulated depletion, depreciation, amortization and impairment	(306,743)	(181,393)
Net property and equipment	1,931,685	1,541,500
Operating lease right-of-use assets	18,017	19,502
Intangible assets, net	79,128	88,248
Restricted cash for future asset retirement obligations	47,359	46,673
Other assets	45,080	31,625
Total assets	2,327,499	1,902,953
Current liabilities
Accounts payable and accrued liabilities	248,800	191,598
Oil and gas production payable	80,368	75,899
Derivative liabilities	13,018	134,509
Operating lease liabilities	4,676	4,677
Total current liabilities	346,862	406,683
Long-term liabilities
Long-term debt, net of current portion	29,000	35,000
Asset retirement obligations	315,942	284,238
Deferred tax liabilities, net	71,120	1,638
Operating lease liabilities	15,431	17,094
Other liabilities	16,527	22,910
Total long-term liabilities	448,020	360,880
Commitments and contingencies (Note 14)
Stockholders’ equity
Preferred stock, $0.001 par value, 50,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $0.001 par value, 250,000,000 shares authorized; 49,814,874 and 50,193,656 shares issued, respectively	50	50
Paid-in capital in excess of par	1,047,063	1,129,996
Retained earnings	485,504	5,344
Total stockholders’ equity	1,532,617	1,135,390
Total liabilities and stockholders’ equity	$ 2,327,499	$ 1,902,953

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Stockholders’ equity
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	50,000,000	50,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	250,000,000	250,000,000
Common stock, shares issued (in shares)	49,814,874	50,193,656

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Revenues	$ 215,903	$ 521,693	$ 1,704,345	$ 1,242,872
Other income	4,697	8,419	10,314	15,288
Revenues and other income	220,600	530,112	1,714,659	1,258,160
Lease operating expenses	101,234	250,271	502,409	424,550
Expenses
Taxes other than income	16,584	43,531	131,502	91,390
General and administrative expenses	19,470	48,522	82,180	79,258
Interest, net of amounts capitalized of $4,237, $4,585, $1,261, and $22,885, respectively	1,815	48,267	4,025	4,147
Depletion, depreciation, and amortization	45,812	188,593	151,428	150,640
Commodity derivatives expense (income)	61,902	(102,032)	178,744	352,984
Gain on debt extinguishment	0	(18,994)	0	0
Write-down of oil and natural gas properties	1,006	996,658	0	14,377
Reorganization items, net	0	849,980	0	0
Other expenses	8,072	35,868	16,284	10,816
Total expenses	273,784	2,378,819	1,159,655	1,201,391
Income (loss) before income taxes	(53,184)	(1,848,707)	555,004	56,769
Income tax provision (benefit)	(2,526)	(416,129)	74,844	767
Net income (loss)	$ (50,658)	$ (1,432,578)	$ 480,160	$ 56,002
Net income (loss) per common share
Basic (in dollars per share)	$ (1.01)	$ (2.89)	$ 9.34	$ 1.10
Diluted (in dollars per share)	$ (1.01)	$ (2.89)	$ 8.83	$ 1.04
Weighted average common shares outstanding
Basic (in shares)	50,000	495,560	51,427	50,918
Diluted (in shares)	50,000	495,560	54,355	53,818
Oil, natural gas, and related product sales
Revenues	$ 201,108	$ 492,101	$ 1,578,682	$ 1,159,955
Expenses
Operating expenses	10,595	27,164	20,112	28,817
CO2
Revenues	9,419	21,049	60,570	44,175
Expenses
Operating expenses	1,976	2,592	8,474	6,678
Oil marketing revenues
Revenues	5,376	8,543	65,093	38,742
Expenses
Operating expenses	$ 5,318	$ 8,399	$ 64,497	$ 37,734

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, 2022	Dec. 31, 2021
Income Statement [Abstract]
Capitalized interest	$ 1,261	$ 22,885	$ 4,237	$ 4,585

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities
Net income (loss)	$ (50,658)	$ (1,432,578)	$ 480,160	$ 56,002
Adjustments to reconcile net income (loss) to cash flows from operating activities
Noncash reorganization items, net	0	810,909	0	0
Depletion, depreciation, and amortization	45,812	188,593	151,428	150,640
Write-down of oil and natural gas properties	1,006	996,658	0	14,377
Deferred income taxes	(2,556)	(408,869)	69,481	364
Stock-based compensation	8,212	4,111	16,055	25,322
Commodity derivatives expense (income)	61,902	(102,032)	178,744	352,984
Receipt (payment) on settlements of commodity derivatives	21,089	81,396	(315,752)	(277,240)
Gain on debt extinguishment	0	(18,994)	0	0
Debt issuance costs and discounts	799	11,571	2,996	2,740
Gain from asset sales and other	(3,546)	(6,723)	(1,232)	(10,609)
Other, net	1,197	7,162	(13,198)	(2,465)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	21,411	26,575	(911)	(51,944)
Trade and other receivables	15,567	(22,343)	(8,241)	(284)
Other current and long-term assets	(1,795)	743	(9,659)	10,390
Accounts payable and accrued liabilities	(67,167)	(16,102)	964	28,500
Oil and natural gas production payable	(6,912)	(6,792)	4,469	29,351
Asset retirement obligation settlements	(3,439)	(2,465)	(34,260)	(10,185)
Other liabilities	(596)	2,588	(299)	(785)
Net cash provided by operating activities	40,326	113,408	520,745	317,158
Cash flows from investing activities
Oil and natural gas capital expenditures	(17,964)	(99,582)	(317,094)	(150,911)
CCUS storage sites and related capital expenditures	0	0	(59,880)	0
Acquisitions of oil and natural gas properties	(82)	0	(976)	(10,979)
Pipeline capital expenditures	(618)	(11,601)	(23,478)	(69,223)
Net proceeds from sales of oil and natural gas properties and equipment	938	41,322	237	19,053
Equity investment	0	0	(10,218)	0
Other	15,842	12,747	(16,521)	9,128
Net cash used in investing activities	(1,884)	(57,114)	(427,930)	(202,932)
Cash flows from financing activities
Bank repayments	(190,000)	(551,000)	(1,015,000)	(933,000)
Bank borrowings	120,000	691,000	1,009,000	898,000
Common stock repurchase program	0	0	(100,028)	0
Pipeline financing and capital lease debt repayments	(22,938)	(51,792)	0	(68,008)
Interest payments treated as a reduction of debt	0	(46,417)	0	0
Cash paid in conjunction with debt repurchases	0	(14,171)	0	0
Other	1,630	(21,845)	10,749	(3,122)
Net cash provided by (used in) financing activities	(91,308)	5,775	(95,279)	(106,130)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(52,866)	62,069	(2,464)	8,096
Cash, cash equivalents, and restricted cash at beginning of period	95,114	33,045	50,344	42,248
Cash, cash equivalents, and restricted cash at end of period	$ 42,248	$ 95,114	$ 47,880	$ 50,344

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock ($.001 Par Value)	Paid-In Capital in Excess of Par	Retained Earnings (Accumulated Deficit)	Treasury Stock (at cost)
Beginning balance (in shares) at Dec. 31, 2019		508,065,495
Beginning balance (in shares) at Dec. 31, 2019					1,652,771
Beginning balance at Dec. 31, 2019	$ 1,412,259	$ 508	$ 2,739,099	$ (1,321,314)	$ (6,034)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net issued pursuant to stock compensation plans (in shares)		312,516
Issued pursuant to directors' compensation plan (in shares)		37,367
Stock-based compensation	14,317		14,317
Issued pursuant to notes conversion (in shares)		7,372,250
Issued pursuant to notes conversion	11,501	$ 8	11,493
Canceled pursuant to stock compensation plans (in shares)		(6,313,884)
Canceled pursuant to stock compensation plans	0	$ (6)	6
Tax withholding for stock compensation plans (in shares)					(742,862)
Tax withholding for stock compensation plans	(168)				$ (168)
Net income (loss)	(1,432,578)			(1,432,578)
Cancellation of Predecessor equity (in shares)		(509,473,744)			(2,395,633)
Cancellation of Predecessor equity	(5,331)	$ (510)	(2,764,915)	2,753,892	$ 6,202
Issuance of Successor equity (in shares)		49,999,999
Issuance of Successor equity	1,095,419	$ 50	1,095,369
Ending balance (in shares) at Sep. 18, 2020		49,999,999
Ending balance (in shares) at Sep. 18, 2020					0
Ending balance at Sep. 18, 2020	1,095,419	$ 50	1,095,369	0	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	8,907		8,907
Issued pursuant to notes conversion	0
Net income (loss)	(50,658)			(50,658)
Ending balance (in shares) at Dec. 31, 2020		49,999,999
Ending balance (in shares) at Dec. 31, 2020					0
Ending balance at Dec. 31, 2020	1,053,668	$ 50	1,104,276	(50,658)	$ 0
Beginning balance (in shares) at Sep. 18, 2020		49,999,999
Beginning balance (in shares) at Sep. 18, 2020					0
Beginning balance at Sep. 18, 2020	$ 1,095,419	$ 50	1,095,369	0	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issued pursuant to exercise of warrants (in shares)	1,300,000
Ending balance (in shares) at Dec. 31, 2022	49,814,874	49,814,874
Ending balance (in shares) at Dec. 31, 2022					0
Ending balance at Dec. 31, 2022	$ 1,532,617	$ 50	1,047,063	485,504	$ 0
Beginning balance (in shares) at Dec. 31, 2020		49,999,999
Beginning balance (in shares) at Dec. 31, 2020					0
Beginning balance at Dec. 31, 2020	1,053,668	$ 50	1,104,276	(50,658)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	27,205		27,205
Issued pursuant to notes conversion	0
Tax withholding for stock compensation plans	(2,244)		(2,244)
Net income (loss)	56,002			56,002
Issued pursuant to exercise of warrants (in shares)		193,657
Issued pursuant to exercise of warrants	$ 759		759
Ending balance (in shares) at Dec. 31, 2021	50,193,656	50,193,656
Ending balance (in shares) at Dec. 31, 2021					0
Ending balance at Dec. 31, 2021	$ 1,135,390	$ 50	1,129,996	5,344	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net issued pursuant to stock compensation plans (in shares)		152,955
Stock-based compensation	17,067		17,067
Issued pursuant to notes conversion	0
Tax withholding for stock compensation plans (in shares)		(35)			(35)
Tax withholding for stock compensation plans	(939)		(937)		$ (2)
Employee stock purchase plan (in shares)		7,604
Employee stock purchase plan	561		561
Net income (loss)	480,160			480,160
Issued pursuant to exercise of warrants (in shares)		1,076,050
Issued pursuant to exercise of warrants	406	$ 1	405
Stock repurchase program (in shares)		1,615,356			1,615,356
Stock repurchase program	(100,028)				$ (100,028)
Retired Treasury Shares (in shares)					(1,615,391)
Retired Treasury Shares	$ 0	$ (1)	(100,029)		$ (100,030)
Ending balance (in shares) at Dec. 31, 2022	49,814,874	49,814,874
Ending balance (in shares) at Dec. 31, 2022					0
Ending balance at Dec. 31, 2022	$ 1,532,617	$ 50	$ 1,047,063	$ 485,504	$ 0

Nature of Operations and Summar

Nature of Operations and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Nature of Operations and Summary of Significant Accounting Policies	Note 1. Nature of Operations and Summary of Significant Accounting Policies Organization and Nature of Operations Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. The Company is differentiated by its focus on CO 2 EOR and the emerging CCUS industry, supported by the Company’s CO 2 EOR technical and operational expertise and extensive CO 2 pipeline infrastructure. We adopted fresh start accounting upon emergence from voluntary reorganization under Chapter 11 of the Bankruptcy Code in September 2020 at which point we became a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of our Plan of Reorganization, the financial statements after September 18, 2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies. References to "Predecessor” refer to the Company for periods ended on or prior to September 18, 2020 and references to “Successor” refer to the Company for periods subsequent to September 18, 2020. See Note 2, Fresh Start Accounting for additional information on our bankruptcy proceedings and the impact of fresh start accounting on our consolidated financial statements. 2020 Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code 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”). 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. We have no remaining obligations related to this reorganization. On the Emergence Date and pursuant to the terms of the Plan and the Confirmation Order, all outstanding obligations under Denbury’s previously issued notes were fully extinguished, relieving approximately $2.1 billion in aggregate principal of debt by issuing equity and/or warrants in the Successor to the former holders of that debt, and the Company: • Adopted an amended and restated certificate of incorporation and bylaws which reserved for issuance 250,000,000 shares of common stock, par value $0.001 per share, of Denbury (the “New Common Stock”) and 50,000,000 shares of preferred stock, par value $0.001 per share; • Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor. In accordance with the Plan, claims against and interests in the Predecessor were treated as follows: ◦ Holders of secured pipeline lease claims received payment in full in cash, the collateral securing such pipeline lease claim, reinstatement, or such other treatment rendering such pipeline lease claim unimpaired (see Note 8, Long-Term 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 “Bank Credit Agreement”) with total aggregate commitments of $575 million; 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. Such charges 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 segregation of “Reorganization items, net” as a separate line in the Consolidated Statements of Operations. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Principles of Reporting and Consolidation The consolidated financial statements herein have been prepared in accordance with GAAP and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable 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; (9) estimates made in determining the fair values for purchase price allocations; and (10) other estimates recorded as a result of the adoption of fresh start accounting (see Note 2, Fresh Start Accounting) . While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. Business Segment Information We have evaluated our organization and management of our business, as well as the information we use to make resource allocations, and have determined that we have one operating segment. Management measures financial performance for the Company as a whole and, at this time, does not assess performance of oil and gas operations separately from our emerging CCUS business. While we have been actively engaged in pursuing emerging CCUS business activities as a natural extension of our historic CO 2 EOR operations and CO 2 pipeline infrastructure, to date we do not have revenues associated with capturing, transporting and sequestering CO 2 emissions for dedicated storage and the expenses associated with these activities are immaterial to our consolidated financial statements. We have recorded $65.0 million of CCUS assets on our Consolidated Balance Sheet as of December 31, 2022 and incurred $59.9 million of CCUS capital expenditures on our Consolidated Statement of Cash Flows for the year ended December 31, 2022, most of which is attributable to the development of CO 2 storage sites for future sequestration of captured industrial emissions. 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 and other income, total expenses, net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity. Cash, Cash Equivalents, and Restricted Cash We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows: In thousands December 31, 2022 December 31, 2021 Cash and cash equivalents $ 521 $ 3,671 Restricted cash for future asset retirement obligations 47,359 46,673 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 47,880 $ 50,344 Restricted cash for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligation. Oil and Natural Gas Properties Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion. The costs capitalized, including production equipment and future development costs, are depleted using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. Impairment of Unevaluated Oil and Natural Gas Properties. 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. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 coronavirus pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting ). 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 CO 2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized 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 $93.02 at December 31, 2022, $63.86 at December 31, 2021, $35.84 at December 31, 2020, and $40.08 at September 18, 2020. We did not recognize a full cost pool ceiling test write-down during the year ended December 31, 2022. During the year ended December 31, 2021, we recognized a $14.4 million full cost pool ceiling test write-down primarily as a result of the March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures ) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. Primarily as a result of the commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. 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 50 years. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles are generally depreciated over a useful life of five years, furniture and fixtures over a life of ten years, and computer equipment and software are generally depreciated over a useful life of three Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred. Intangible Assets Our intangible assets subject to amortization represent amounts assigned 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 September 18, 2020. The following table summarizes the carrying value of our intangible assets as of December 31, 2022 and 2021: In thousands December 31, 2022 December 31, 2021 Long-term contracts to sell CO 2 to industrial customers $ 97,943 $ 97,943 Other intangibles 2,179 2,179 Accumulated amortization (20,994) (11,874) Net book value $ 79,128 $ 88,248 As of December 31, 2022, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2023 $ 9,117 2024 9,117 2025 9,117 2026 9,117 2027 8,832 CCUS Storage Sites and Other Assets Capitalized Costs. We capitalize costs that we incur to lease, acquire and develop storage sites for the injection of CO 2 . These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; the acquisition of seismic data, permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If it is determined that a storage site is no longer probable of being pursued, developed or utilized, all previously capitalized costs associated with that site are expensed. Amortization. Our CCUS storage sites are currently in the development stage and not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO 2 storage operations commence. Investment in Project Development Company (“Clean Hydrogen Works”) of Planned Louisiana Blue Hydrogen Ammonia Project. During 2022, we made a $10 million investment in the project development company of a planned blue hydrogen/ammonia multi-block facility, while also signing a definitive agreement for the transportation and storage of CO 2 for the first two blocks of the proposed plant. We have committed to invest another $10 million when certain milestones are achieved, currently expected to occur in 2023. The investment is included in “Other assets” in the Consolidated Balance Sheet as of December 31, 2022. 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, pipelines and CCUS assets, and also include long-term contracts to sell CO 2 to industrial customers. We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized 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. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. We did not record an impairment of long-lived assets during the year ended December 31, 2022 and 2021, the Successor Period from September 19, 2020 through December 31, 2020 or the Predecessor period from January 1, 2020 through September 18, 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 year ended December 31, 2022, two purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (27%) and Hunt Crude Oil Supply Company (11%). For the year ended December 31, 2021, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (28%), Hunt Crude Oil Supply Company (12%), Marathon Petroleum (11%) and Sunoco Inc. (11%), and for the Successor period September 19, 2020 through December 30, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Marathon Petroleum (13%) and Hunt Crude Oil Supply Company (12%). For the Predecessor period January 1, 2020 through September 18, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Hunt Crude Oil Supply Company (12%) and Marathon Petroleum (12%). Income Taxes Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculated basic net income (loss) per common share. Restricted stock units and performance stock units are also excluded from basic weighted average common shares outstanding until the vesting date. Basic weighted average common shares during the year ended December 31, 2022 includes 1,784,474 performance-based and restricted stock units which were fully vested as of December 31, 2022; however, the shares underlying these awards are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023. Diluted net income (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”) and series A and series B warrants, and during the Predecessor periods consisted of restricted stock,

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2022
Reorganizations [Abstract]
Fresh Start Accounting	Note 2. Fresh Start Accounting Fresh Start Accounting Upon emergence from bankruptcy in 2020, we adopted 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. 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. Reorganization Value Upon Emergence 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, net” in our Consolidated Statements of Operations includes (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments. Professional service provider charges associated with our restructuring that were incurred outside of this period (before the Petition Date and after the Emergence Date) are recorded in “Other expenses” in our Consolidated Statements of Operations. Contractual interest expense of $22.0 million from the Petition Date through the Emergence Date associated with our outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes was not accrued or recorded in the consolidated statement of operations as interest expense. The following table summarizes the losses (gains) on reorganization items, net: 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 Debtor-in-possession credit agreement fees 3,107 Acceleration of Predecessor stock compensation expense 4,601 Total reorganization items, net $ 849,980 Valuation Process Upon Emergence 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 estimated by management, and income was imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily develop or produce natural gas. Cash flows were also adjusted for a market participant profit on 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 estimated by management, and profits were imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily transport natural gas. Pipeline depreciable lives represent the remaining estimated useful lives of the pipelines. Other Property and Equipment The fair value of the non-reserve related property and equipment such as land, buildings, equipment, leasehold improvements and software was determined using the replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. Long-Term Contracts to Sell 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. 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 model. The Black-Scholes model is a pricing model used to estimate the fair value of a European-style call or put option/warrant based on a current stock price, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield. The model used the following assumptions: implied stock price (total equity divided by total shares outstanding) of the Successor’s shares of common stock of $22.14; exercise price per share of $32.59 and $35.41 for series A and B warrants, respectively; expected volatility of 49.3% and 53.6% for series A and B warrants, respectively; risk-free interest rates of 0.3% and 0.2% for series A and B warrants, respectively, using the United States Treasury Constant Maturity rates; and an expected annual dividend yield of 0%. Expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available. The time to maturity of the warrants was based on the contractual terms of the warrants of five 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.

Acquisition and Divestitures

Acquisition and Divestitures	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Acquisition and Divestitures	Note 3. Acquisition and Divestitures Acquisition of Wyoming CO 2 EOR Fields On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation, including surface facilities and a 46-mile CO 2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and the second $4 million payment in January 2023. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of December 31, 2022, the fair value of the contingent consideration recorded on our Consolidated Balance Sheets was $4 million. Fair value changes of $0.3 million and $2.4 million resulting from higher NYMEX WTI oil prices were recorded to “Other expenses” in our Consolidated Statements of Operations for the years ended December 31, 2022 and 2021, respectively. The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition: In thousands Consideration: Cash consideration $ 10,906 Fair value of assets acquired and liabilities assumed: Proved oil and natural gas properties 60,101 Other property and equipment 1,685 Asset retirement obligations (39,794) Contingent consideration (5,320) Other liabilities (5,766) Fair value of net assets acquired $ 10,906 Divestitures Hartzog Draw Deep Mineral Rights On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or proved reserves. Houston Area Land Sales During 2022 and 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We received cash proceeds of $1.4 million and $15.2 million from the sales and recognized $0.8 million and $10.3 million in gains to “Other income” in our Consolidated Statements of Operations for the years ended December 31, 2022 and 2021, respectively. Gulf Coast Working Interests Sale On March 4, 2020, the Predecessor sold half of its working interest positions in four southeast Texas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. The Predecessor did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2022
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 control (the identified performance obligation is satisfied). Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our 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 received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets. In addition to revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts, in certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Disaggregation of Revenue The following table summarizes our revenues by product type: Successor Predecessor Year Ended Year Ended Period from Period from In thousands Oil sales $ 1,559,111 $ 1,148,022 $ 199,769 $ 489,251 Natural gas sales 19,571 11,933 1,339 2,850 CO 2 sales and transportation fees 60,570 44,175 9,419 21,049 Oil marketing revenues 65,093 38,742 5,376 8,543 Total revenues $ 1,704,345 $ 1,242,872 $ 215,903 $ 521,693

Leases

Leases	12 Months Ended
	Dec. 31, 2022
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 13 years, with certain land leases having remaining terms up to 47 years. Leases with a term of 12 months or less are not recorded on our balance sheet. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our office leases: In thousands December 31, 2022 December 31, 2021 Operating leases Operating lease right-of-use assets $ 18,017 $ 19,502 Operating lease liabilities – current $ 4,676 $ 4,677 Operating lease liabilities – long-term 15,431 17,094 Total operating lease liabilities $ 20,107 $ 21,771 The majority of our leases contain renewal options, typically exercisable at our sole discretion. The following table presents weighted average remaining lease terms and discount rates for our outstanding operating leases: December 31, 2022 December 31, 2021 Weighted average remaining lease term 4.5 years 5.2 years Weighted average discount rate 5.7 % 5.4 % We account for lease and nonlease components in a contract as a single lease component for all asset classes. Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. Variable lease costs represent additional payments in excess of our minimum base rental payments under our office space leases. The Predecessor Company previously subleased part of the office space included in its operating leases for which it received rental payments. Since those office space leases were terminated during the Chapter 11 Restructuring, the underlying sublease agreements were also terminated. The Successor Company subsequently entered into an operating lease for a new corporate office space which commenced in October 2020. The following table summarizes the components of lease costs and sublease income: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Income Statement Operating lease cost General and administrative expenses $ 5,532 $ 4,102 $ 872 $ 5,683 Lease operating expenses 178 655 158 214 CO 2 operating and discovery expenses 50 50 14 37 $ 5,760 $ 4,807 $ 1,044 $ 5,934 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ — $ — $ 3 $ 9 Interest on lease liabilities Interest expense — — 1 3 Total finance lease cost $ — $ — $ 4 $ 12 Variable lease cost $ 758 $ 670 $ 258 $ 3,688 Sublease income General and administrative expenses $ — $ — $ 100 $ 2,584 Our statement of cash flows included the following activity related to our operating and finance leases: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 5,903 $ 2,830 $ 341 $ 7,341 Operating cash flows from interest on finance leases — — 1 3 Financing cash flows from finance leases — — 78 10 Right-of-use assets obtained in exchange for lease obligations Operating leases 2,270 2,683 19,902 1,049 Finance leases — — — 162 The following table summarizes by year the maturities of our lease liabilities as of December 31, 2022: Operating In thousands Leases 2023 $ 5,702 2024 4,963 2025 4,974 2026 4,640 2027 1,786 Thereafter 1,023 Total minimum lease payments 23,088 Less: Amount representing interest (2,981) Present value of minimum lease liabilities $ 20,107

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The following table summarizes the changes in our asset retirement obligations: Year Ended Year Ended Dec. 31, 2021 In thousands Beginning asset retirement obligations $ 302,611 $ 186,281 Liabilities incurred and assumed during period 547 43,701 Revisions in estimated retirement obligations 64,667 69,059 Liabilities settled and sold during period (34,260) (10,783) Accretion expense 18,477 14,353 Ending asset retirement obligations 352,042 302,611 Less: current asset retirement obligations (1) (36,100) (18,373) Long-term asset retirement obligations $ 315,942 $ 284,238 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. Liabilities assumed relate to our March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures ), and liabilities incurred generally relate to wells and facilities. Revisions during 2022 are primarily due to increased cost estimates associated with both environmental remediation of the surface areas surrounding our well sites as well as increased subsurface abandonment costs due to rising costs. Revisions during 2021 primarily related to increased well abandonment cost estimates at certain of these fields and an acceleration in the estimated timing of certain future abandonment activities. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $55.9 million and $55.6 million as of December 31, 2022 and 2021, respectively. These balances are primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are included in “Restricted cash for future Asset Retirement obligations” 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, 2022 and 2021.

Unevaluated Property

Unevaluated Property	12 Months Ended
	Dec. 31, 2022
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, 2022, and the year in which the costs were incurred follows: December 31, 2022 Costs Incurred During: In thousands 2022 2021 Successor 2020 Fresh Start Adjustments (Sept. 18, 2020) (1) Total Property acquisition costs $ — $ — $ — $ 64,077 $ 64,077 Exploration and development 132,494 35,881 — — 168,375 Capitalized interest 3,824 3,575 584 — 7,983 Total $ 136,318 $ 39,456 $ 584 $ 64,077 $ 240,435 (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, 2022. 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 and Salt Creek fields. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil field projects at Cedar Creek Anticline that are under development but did not have associated proved reserves at December 31, 2022. 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 . 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, 2022
Debt Disclosure [Abstract]
Long-Term Debt	Note 8. Long-Term Debt The ultimate parent company in our corporate structure, Denbury Inc., is the sole issuer of all our outstanding obligations under our 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. Senior Secured Bank Credit Facility On September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). Under the 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 Bank Credit Agreement. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the 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 undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum. Our outstanding borrowings under the Bank Credit Agreement, totaled $29.0 million and $35.0 million as of December 31, 2022 and December 31, 2021, respectively, and as of December 31, 2022, we had $10.1 million of outstanding letters of credit. On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things: • Increased the borrowing base and lender commitments from $575 million to $750 million; • Extended the maturity date from January 30, 2024 to May 4, 2027; • Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate “(SOFR)” loans, with an applicable margin of 2.5% to 3.5% per annum; and • Permitted us to pay dividends on and repurchase our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base. As part of our Fall 2022 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around May 1, 2023. On January 20, 2023, we entered into a Third Amendment to the Bank Credit Agreement, which among other things, provides us the ability to make and repay certain SOFR loan borrowings on a weekly basis. The Bank Credit Agreement 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 certain exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement. The 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 Bank Credit Agreement contains certain financial performance covenants including the following: • A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and • A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0. For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the 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. The weighted average interest rate on borrowings outstanding as of December 31, 2022 under the Bank Credit Agreement was 9%. As of December 31, 2022, we were in compliance with all debt covenants under the Bank Credit Agreement. The above description of our Bank Credit Agreement and defined terms are contained in the Bank Credit Agreement. Restructuring of Pipeline Financing Transactions In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The NEJD pipeline system included a 20-year secured financing lease, and the Free State Pipeline included a long-term transportation service agreement. In late October 2020, we restructured our CO 2 pipeline financing arrangements with Genesis, whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million which was paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020. 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 $9.2 million and $5.7 million at December 31, 2022 and 2021, respectively. Issuance costs associated with our Bank Credit Agreement are included in “Other assets” in the Consolidated Balance Sheets. Indebtedness Repayment Schedule The $29.0 million total indebtedness as of December 31, 2022 is due in 2027.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Note 9. Income Taxes Our income tax provision (benefit) is as follows: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Current income tax expense (benefit) Federal $ 3,055 $ — $ — $ (6,407) State 2,308 403 30 (853) Total current income tax expense (benefit) 5,363 403 30 (7,260) Deferred income tax expense (benefit) Federal 63,814 — — (319,011) State 5,667 364 (2,556) (89,858) Total deferred income tax expense (benefit) 69,481 364 (2,556) (408,869) Total income tax expense (benefit) $ 74,844 $ 767 $ (2,526) $ (416,129) At December 31, 2022, we had general business credit carryforwards totaling $10.5 million that begin to expire in 2041. In connection with our restructuring in 2020, net operating loss carryforwards (“NOLs”), and tax credit carryforwards for enhanced oil recovery and research and development generated prior to January 1, 2021 were fully reduced in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 pertaining to discharge of indebtedness. At December 31, 2022, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act passed in 2017 are fully refundable and are recorded as a receivable on the balance sheet, and state NOLs and tax credits totaling $48.2 million (before provision for valuation allowance) related to our state operations. 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, 2022 and 2021 balance sheet dates. Based on all available evidence, both positive and negative, we reached a determination as of March 31, 2022, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices and taxable income generated from future reversals of existing taxable temporary differences, to conclude that our federal and certain state deferred tax assets are more likely than not to be realized. Based on this determination, in 2022 we reversed the valuation allowance on our federal and certain state deferred tax assets by $51.4 million and $14.8 million, respectively. The reversal of state valuation allowance relates to certain state deferred tax assets for Mississippi, Montana and North Dakota. As of December 31, 2022, we had $59.2 million of net state deferred tax assets associated with operations in Louisiana, Alabama, as well as certain Mississippi tax credits, 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 Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Beginning balance $ 125,462 $ 129,408 $ 129,840 $ 77,215 Charges 790 29,345 2,269 77,138 Deductions (67,019) (33,291) (2,701) (24,513) Ending balance $ 59,233 $ 125,462 $ 129,408 $ 129,840 Significant components of our deferred tax assets and liabilities as of December 31, 2022 and 2021 are as follows: In thousands December 31, 2022 December 31, 2021 Deferred tax assets Loss and tax credit carryforwards – state $ 48,172 $ 54,943 Derivative contracts — 30,892 Accrued liabilities and other reserves 19,155 19,567 Business credit carryforwards 10,487 18,066 Loss carryforwards – federal — 10,310 Lease liabilities 1,998 4,523 Property and equipment — 2,613 Other 5,974 4,206 Valuation allowances (59,233) (125,462) Total deferred tax assets 26,553 19,658 Deferred tax liabilities Property and equipment (78,055) — CO 2 and other contracts (15,304) (17,208) Operating lease right-of-use assets (2,770) (4,088) Derivative contracts (1,544) — Total deferred tax liabilities (97,673) (21,296) Total net deferred tax liability $ (71,120) $ (1,638) 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 Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Income tax provision calculated using the federal statutory income tax rate $ 116,551 $ 11,921 $ (11,169) $ (388,228) State income taxes 20,642 1,468 8,509 (120,340) Tax windfall on stock-based compensation deduction (158) (267) — (1,380) Nondeductible compensation 2,303 5,057 — — Change in valuation allowance (66,229) (3,946) (432) 52,625 EOR and other (1,530) (14,272) — — Tax attributes reduction – net of cancellation of indebtedness income exclusion — — — 31,667 Other 3,265 806 566 9,527 Total income tax expense (benefit) $ 74,844 $ 767 $ (2,526) $ (416,129) 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 2019 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, 2022
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Note 10. Stockholders’ Equity Registration Rights Agreement On September 18, 2020, in connection with the Company’s emergence from Chapter 11 proceedings, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain former beneficial holders of second lien notes of the Predecessor that entered into the restructuring support agreement leading to the restructuring of the Company pursuant to a prepackaged plan of reorganization and pursuant to which the Company included these holders’ shares of common stock of the Successor in an automatically effective resale registration statement filed with the SEC in April 2021 for their use in connection with resale of these shares. Under the Registration Rights Agreement, these security holders have customary demand and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. 401(k) Plan We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations. We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately. Matching contributions to the 401(k) plan totaled $5.8 million during 2022, $5.1 million during 2021, $1.1 million for the period September 19, 2020 through December 31, 2020 (Successor), and $4.4 million for the period January 1, 2020 through September 18, 2020 (Predecessor). Share Repurchase Program In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During June and July 2022, the Company repurchased 1,615,356 shares of Denbury common stock under this program for approximately $100 million, at an average price of $61.92 per share. In August 2022, the Board increased Denbury’s stock repurchase authorization by $100 million, thus a total of $250 million of common stock currently remains authorized for future repurchases under this program. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program. Retirement of Treasury Stock During the year ended December 31, 2022, we retired 1.6 million shares of existing treasury stock, with a carrying value of $100.0 million, acquired primarily through our stock repurchase program. Upon the retirement of treasury stock, we reduce common stock by the par value of common stock retired, and we reduce additional paid-in capital by the value of those shares in excess of par value. Employee Stock Purchase Plan – Successor On June 1, 2022, the Company’s stockholders approved the Denbury Inc. Employee Stock Purchase Plan authorizing the sale of up to 2,000,000 shares of common stock thereunder. In accordance with the ESPP, full-time employees may contribute up to 10% of their base salary, subject to certain limitations, to purchase previously unissued Denbury common stock. Participants in the ESPP may purchase common stock at a 15% discount to the fair market value of a share of common stock determined as the lower of the closing sales price on the first or last trading day of each offering period. The first offering period under the ESPP commenced on September 1, 2022 and ended on December 31, 2022 for which the Company issued 7,604 shares. The plan is administered by the Compensation Committee of our Board of Directors.

Stock Compensation

Stock Compensation	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Stock Compensation	Note 11. Stock Compensation Below is a description of stock compensation relating to both the Predecessor period (January 1, 2020 through September 18, 2020), and the Successor periods (September 19, 2020 through December 31, 2020, and each of the years ending December 31, 2021 and 2022). 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, 2022. 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 Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Stock-based compensation expense included in G&A $ 16,055 $ 25,322 $ 8,212 $ 4,111 Stock-based compensation capitalized 1,012 1,883 695 1,660 Total cost of stock-based compensation arrangements $ 17,067 $ 27,205 $ 8,907 $ 5,771 Income tax benefit recognized for stock-based compensation arrangements $ 1,663 $ 1,846 $ 2,053 $ 1,028 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, 2022, 3.6 million shares were available for future grants under the LTIP, all of which could be issued in the form of restricted stock, 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 and Awards – Successor Non-performance-based restricted stock unit (“RSU”) awards were granted to a limited number of employees and Directors in December of 2020 and to Directors in March 2022 under the Successor’s LTIP. Additionally, in March 2022, we granted non-performance-based restricted stock awards to employees under the Successor’s LTIP. Holders of non-performance-based RSUs will receive shares of Successor common stock equal to the number of RSUs that have vested upon settlement. Non-performance-based RSUs generally vest ratably over a three-year period with delivery of the shares occurring at the end of the three-year period. Vested non-performance-based RSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying RSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. The grant-date fair value of the RSUs is based on the fair market value of our common stock on the date of grant. Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Non- performance-based restricted stock awards vest ratably over a three-year period, with the specific terms of vesting determined at the time of grant and delivery of the shares occurring upon vesting. Non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. The grant-date fair value of the restricted stock awards is based on the fair market value of our common stock on the date of grant. As of December 31, 2022, there was $9.3 million and $8.7 million of unrecognized compensation expense related to the Successor’s non-performance-based restricted stock unit grants and restricted stock awards, respectively. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 0.9 years and 1.6 years, respectively. The following is a summary of the total vesting date fair value of non-performance-based restricted stock and the weighted average grant-date fair value of restricted stock granted of units and awards: Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 In thousands, except weighted-average grant-date fair value Fair value of restricted stock units vested $ 36,047 $ 31,073 $ — Weighted-average grant-date fair value of restricted stock units granted during year 76.08 31.87 24.67 Fair value of restricted stock awards vested $ 6 $ — $ — Weighted-average grant-date fair value of restricted stock awards granted during year 76.87 — — A summary of the status of our non-performance-based RSUs and restricted stock awards issued and the changes during the year ended December 31, 2022 (Successor) period is presented below: Restricted Stock Units Number Weighted Nonvested at December 31, 2021 849,907 $ 25.08 Granted 15,893 76.08 Vested (412,065) 25.05 Forfeited (23,842) 24.67 Nonvested at December 31, 2022 429,893 27.02 Restricted Stock Awards Number Weighted Nonvested at December 31, 2021 — $ — Granted 158,692 76.87 Vested (98) 76.08 Forfeited (5,737) 76.08 Nonvested at December 31, 2022 152,857 76.90 Performance-Based Stock Units – Successor In December 2020 and March 2022, the Successor Board of Directors granted performance stock unit (“PSU”) awards to a limited number of employees. The PSU awards granted in December 2020 had vesting parameters tied to the Company’s common stock trading prices and became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, delivery of the shares will not occur until the conclusion of the three-year performance period, December 4, 2023. The PSU awards granted in March 2022 vest over approximately 3 years and the number of performance-based awards earned (and eligible to vest) during the performance period will depend upon the performance of our stock relative to that of a designated peer group. Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the target number of shares will be earned if the maximum target levels are met (200% of target vesting levels). The shares earned will be issued upon vesting of the award on March 1, 2025. Vested performance-based PSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying PSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. PSU awards are valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date. As of December 31, 2022, there was $6.9 million of remaining unrecognized compensation expense related to the Successor’s PSU awards. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.2 years. The range of assumptions used in the Monte Carlo simulation valuation approach is as follows: Successor Year Ended Period from Sept. 19, 2020 through Dec. 31, 2020 Weighted average fair value of PSU awards granted $ 89.43 $ 24.19 Weighted average risk-free interest rate 1.76 % 0.21 % Expected life 2.96 years 0.23 years Weighted average expected volatility 61.6 % 110.0 % Dividend yield — % — % A summary of the PSU awards activity during the year ended December 31, 2022 (Successor) is as follows: Number Weighted Nonvested at December 31, 2021 — $ — Granted 110,385 89.43 Vested — — Forfeited (4,273) 90.86 Nonvested at December 31, 2022 106,112 89.37 The following is a summary of the total vesting date fair value and weighted average grant-date fair value of PSU awards: Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 In thousands, except weighted average grant date fair value Fair value of performance stock units vested $ — 45,077 — Weighted-average grant-date fair value of performance stock units granted during year 89.43 — 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 settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock were authorized for issuance pursuant to the 2004 Plan. In connection with our emergence from bankruptcy, all outstanding equity as of September 18, 2020 was cancelled. Restricted Stock – Predecessor During the Predecessor period, we granted non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards had the rights of owning non-restricted stock (including voting rights) except that the holders were not entitled to delivery of a portion thereof until certain requirements were met. Beginning in 2014, non-performance-based restricted stock awards provided the holders with forfeitable dividend equivalent rights which vested with the underlying shares. Non-performance-based restricted stock vested over a three-year vesting period, with the specific terms of vesting determined at the time of grant. The following is a summary of the total vesting date fair value of non-performance-based restricted stock: Period from Jan. 1, 2020 through Sept. 18, 2020 In thousands Fair value of restricted stock vested $ 707 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 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 2020. The number of performance-based shares earned (and eligible to vest) during the performance period was dependent upon: (1) the level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of the Predecessor’s stock relative to that of a designated peer group (“Performance-Based TSR Awards”). Performance-Based Operational Awards were valued using the fair market value of the Predecessor’s stock, and Performance-Based TSR Awards were valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) is as follows: Period from Jan. 1, 2020 through Sept. 18, 2020 Weighted average fair value of Performance-Based TSR Awards granted $ 0.15 Risk-free interest rate 0.27 % Expected life 3.0 years Expected volatility 89.6 % Dividend yield — % The following is a summary of the total vesting date fair value of performance-based equity awards for the Predecessor: Period from Jan. 1, 2020 through Sept. 18, 2020 In thousands Fair value of Performance-Based TSR awards vested 79 In June 2020, all outstanding performance-based equity awards were cancelled and replaced with a cash retention incentive (see June 2020 Compensation Adjustments – Predecessor ); there was no remaining compensation cost as of September 18, 2020 to be recognized in future periods related to performance-based equity awards.

Commodity Derivative Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts	Note 12. Commodity Derivative Contracts We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. 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 Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2022, 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, 2022, 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) Weighted Average Price Swap Floor Ceiling Oil Contracts: 2023 Fixed-Price Swaps Jan – Jun NYMEX 9,500 $ 76.65 $ — $ — July – Dec NYMEX 11,000 78.48 — — 2023 Collars Jan – Jun NYMEX 17,500 $ — $ 69.71 $ 100.42 July – Dec NYMEX 9,000 — 68.33 100.69

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
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. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021: Fair Value Measurements Using: Quoted Prices Significant Significant In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2022 Assets Oil derivative contracts – current $ — $ 15,517 $ — $ 15,517 Oil derivative contracts – long-term — — — — Total Assets $ — $ 15,517 $ — $ 15,517 Liabilities Oil derivative contracts – current $ — $ (13,018) $ — $ (13,018) Oil derivative contracts – long-term — — — — Total Liabilities $ — $ (13,018) $ — $ (13,018) December 31, 2021 Liabilities Oil derivative contracts – current $ — $ (134,509) $ — $ (134,509) Oil derivative contracts – long-term — — — — Total Liabilities $ — $ (134,509) $ — $ (134,509) Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated Statements of Operations. Other Fair Value Measurements The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair value of the principal amount of our debt as of December 31, 2022 and 2021 was $29.0 million and $35.0 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
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 cancellable only upon the occurrence of specified future events. The commitments continue for up to 6 years. The price we will pay for CO 2 generally varies depending on the amount of CO 2 delivered and the price of oil. In addition, we have a processing fee contract related to our overriding royalty interest in the CO 2 at LaBarge Field. Our annual commitment under these contracts could range from $40.6 million to $52.0 million in 2023, assuming a $75 per Bbl NYMEX oil price and declines in future years as the CO 2 purchase contract commitments expire. During the first quarter of 2022, we entered into a CO 2 storage agreement that included two non-cancellable payments of $2 million, totaling $4 million, due in 2023 and 2024. We are party to long-term contracts that require us to deliver CO 2 to our customers who are industrial end-users of CO 2 or EOR customers at various contracted prices. Based upon the maximum daily contract quantities as stated in the industrial contracts, total amounts deliverable to these customers could be up to 478 Bcf of CO 2 over the next 12 years. Litigation We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated. On May 26, 2022, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (“NOPV”) relating to the February 2020 pipeline failure near Satartia, Mississippi in our CO 2 pipeline running between the Tinsley and Delhi fields. The NOPV proposed a preliminarily assessed civil penalty of $3.9 million in connection with the incident, which we recorded in our second quarter of 2022 financial statements. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV. 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, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Details	Note 15. Additional Balance Sheet Details Trade and Other Receivables, Net In thousands December 31, 2022 December 31, 2021 Trade accounts receivable, net $ 19,619 $ 10,832 Federal income tax receivable, net 597 597 Other receivables 7,127 7,841 Total $ 27,343 $ 19,270 Rollforward of Allowance for Doubtful Accounts Successor Predecessor Year Ended Year Ended Period from Period from In thousands Beginning balance $ 18,947 $ 23,206 $ 22,146 $ 17,137 Provision for doubtful accounts 1,270 826 1,060 5,297 Write-offs — (5,085) — (288) Ending balance $ 20,217 $ 18,947 $ 23,206 $ 22,146 Accounts Payable and Accrued Liabilities In thousands December 31, 2022 December 31, 2021 Accounts payable $ 58,905 $ 25,700 Accrued asset retirement obligations – current 36,100 18,373 Accrued lease operating expenses 29,454 27,901 Accrued exploration and development costs 28,963 18,936 Accrued compensation 27,025 23,735 Taxes payable 19,487 14,453 Accrued derivative settlements 9,452 27,336 Other 39,414 35,164 Total $ 248,800 $ 191,598

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 16. Supplemental Cash Flow Information Supplemental Cash Flow Information Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Supplemental cash flow information Cash paid for interest, expensed $ 1,961 $ 4,227 $ 813 $ 29,357 Cash paid for interest, capitalized 4,237 4,585 1,261 22,885 Cash paid for interest, treated as a reduction of debt — — — 46,417 Cash paid for income taxes 7,543 184 — 453 Cash received from income tax refunds 3 3 10,457 1,932 Noncash investing and financing activities Increase in asset retirement obligations 65,214 112,760 23,398 4,328 Increase (decrease) in liabilities for capital expenditures 27,271 35,679 1,867 (12,809) Conversion of convertible senior notes into common stock — — — 11,501

Nature of Operations and Summ_2

Nature of Operations and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
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; (9) estimates made in determining the fair values for purchase price allocations; and (10) other estimates recorded as a result of the adoption of fresh start accounting (see Note 2, Fresh Start Accounting) . While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Business Segment Information	Business Segment Information We have evaluated our organization and management of our business, as well as the information we use to make resource allocations, and have determined that we have one operating segment. Management measures financial performance for the Company as a whole and, at this time, does not assess performance of oil and gas operations separately from our emerging CCUS business. While we have been actively engaged in pursuing emerging CCUS business activities as a natural extension of our historic CO 2 EOR operations and CO 2 pipeline infrastructure, to date we do not have revenues associated with capturing, transporting and sequestering CO 2
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 and other income, total expenses, net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Cash, Cash Equivalents, and Restricted Cash	Cash, Cash Equivalents, and Restricted Cash We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows: In thousands December 31, 2022 December 31, 2021 Cash and cash equivalents $ 521 $ 3,671 Restricted cash for future asset retirement obligations 47,359 46,673 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 47,880 $ 50,344 Restricted cash for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligation.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion. The costs capitalized, including production equipment and future development costs, are depleted using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. Impairment of Unevaluated Oil and Natural Gas Properties. 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. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 coronavirus pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting ). 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 CO 2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized 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 $93.02 at December 31, 2022, $63.86 at December 31, 2021, $35.84 at December 31, 2020, and $40.08 at September 18, 2020. We did not recognize a full cost pool ceiling test write-down during the year ended December 31, 2022. During the year ended December 31, 2021, we recognized a $14.4 million full cost pool ceiling test write-down primarily as a result of the March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures ) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. Primarily as a result of the commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. 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.
CO2 Properties, Pipelines, and Property and Equipment - Other	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 50 years. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles are generally depreciated over a useful life of five years, furniture and fixtures over a life of ten years, and computer equipment and software are generally depreciated over a useful life of three Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.
Intangible Assets	Intangible Assets Our intangible assets subject to amortization represent amounts assigned to long-term contracts to sell CO 2 to industrial customers. We amortize the CO 2 seven
CCUS Storage Sites and Other Assets	CCUS Storage Sites and Other Assets Capitalized Costs. We capitalize costs that we incur to lease, acquire and develop storage sites for the injection of CO 2 . These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; the acquisition of seismic data, permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If it is determined that a storage site is no longer probable of being pursued, developed or utilized, all previously capitalized costs associated with that site are expensed. Amortization. Our CCUS storage sites are currently in the development stage and not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO 2 storage operations commence.
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, pipelines and CCUS assets, and also include long-term contracts to sell CO 2 to industrial customers. We perform our long-lived asset impairment test by comparing the net carrying costs of our long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2
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, expectation of future commodity prices, and occasionally requirements under our bank credit facility. 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 Bank Credit Agreement (or affiliates of such lenders). As of December 31, 2022, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
Concentrations of Credit Risk	Concentrations of Credit Risk Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). There are no margin requirements with the counterparties of our derivative contracts.
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 (Loss) 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. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculated basic net income (loss) per common share. Restricted stock units and performance stock units are also excluded from basic weighted average common shares outstanding until the vesting date. Basic weighted average common shares during the year ended December 31, 2022 includes 1,784,474 performance-based and restricted stock units which were fully vested as of December 31, 2022; however, the shares underlying these awards are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023. Diluted net income (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”) and series A and series B warrants, and during the Predecessor periods consisted of restricted stock, performance-based equity awards, and convertible senior notes. The following table sets forth the weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Successor Predecessor Year Ended Year Ended Period from Period from In thousands Weighted average common shares outstanding – basic 51,427 50,918 50,000 495,560 Effect of potentially dilutive securities Restricted stock, restricted stock units and performance stock units 622 762 — — Warrants 2,306 2,138 — — Weighted average common shares outstanding – diluted 54,355 53,818 50,000 495,560 For each of the periods from September 19, 2020 through December 31, 2020 (Successor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 50.0 million for the period September 19, 2020 through December 31, 2020 and 584.4 million for the period January 1, 2020 through September 18, 2020, if the Company had recognized net income during those periods. For purposes of calculating diluted weighted average common shares for the years ended December 31, 2022 and 2021, unvested restricted stock units, unvested restricted stock, unvested performance stock units, ESPP shares and unexercised warrants are included in the diluted shares computation using the treasury stock method. The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the year ended December 31, 2022, year ended December 31, 2021, and the period September 19, 2020 through December 31, 2020, as their effect would have been antidilutive, as of the respective dates: In thousands December 31, 2022 December 31, 2021 December 31, 2020 Restricted stock, restricted stock units and performance stock units 11 — 1,220 Warrants — — 5,526 Employee Stock Purchase Plan — — —
Environmental and Litigation Contingencies	Environmental and Litigation Contingencies The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors. Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Income Taxes. In December 2019, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
Revenue Recognition	We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers . The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition. Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and 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 control (the identified performance obligation is satisfied). Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our 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 received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets. In addition to revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts, in certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.
Leases	We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 13 years, with certain land leases having remaining terms up to 47 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.We account for lease and nonlease components in a contract as a single lease component for all asset classes. Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term.
Stock Compensation	Restricted Stock Units and Awards – Successor Non-performance-based restricted stock unit (“RSU”) awards were granted to a limited number of employees and Directors in December of 2020 and to Directors in March 2022 under the Successor’s LTIP. Additionally, in March 2022, we granted non-performance-based restricted stock awards to employees under the Successor’s LTIP. Holders of non-performance-based RSUs will receive shares of Successor common stock equal to the number of RSUs that have vested upon settlement. Non-performance-based RSUs generally vest ratably over a three-year period with delivery of the shares occurring at the end of the three-year period. Vested non-performance-based RSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying RSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. The grant-date fair value of the RSUs is based on the fair market value of our common stock on the date of grant. Holders of non-performance-based restricted stock awards have the rights of owning non-restricted stock (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Non- performance-based restricted stock awards vest ratably over a three-year period, with the specific terms of vesting determined at the time of grant and delivery of the shares occurring upon vesting. Non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. The grant-date fair value of the restricted stock awards is based on the fair market value of our common stock on the date of grant. Restricted Stock – Predecessor During the Predecessor period, we granted non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards had the rights of owning non-restricted stock (including voting rights) except that the holders were not entitled to delivery of a portion thereof until certain requirements were met. Beginning in 2014, non-performance-based restricted stock awards provided the holders with forfeitable dividend equivalent rights which vested with the underlying shares. Non-performance-based restricted stock vested over a three-year vesting period, with the specific terms of vesting determined at the time of grant. Performance-Based Equity Awards – Predecessor The Predecessor’s Compensation Committee of the Board of Directors annually granted performance-based equity awards to Denbury’s officers. Performance-based awards generally vested over 3.25 years for awards granted in 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”).
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. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

Nature of Operations and Summ_3

Nature of Operations and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
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: In thousands December 31, 2022 December 31, 2021 Cash and cash equivalents $ 521 $ 3,671 Restricted cash for future asset retirement obligations 47,359 46,673 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 47,880 $ 50,344
Schedule of Intangible Assets	The following table summarizes the carrying value of our intangible assets as of December 31, 2022 and 2021: In thousands December 31, 2022 December 31, 2021 Long-term contracts to sell CO 2 to industrial customers $ 97,943 $ 97,943 Other intangibles 2,179 2,179 Accumulated amortization (20,994) (11,874) Net book value $ 79,128 $ 88,248
Schedule of Future Amortization Expense of Intangible Assets	As of December 31, 2022, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2023 $ 9,117 2024 9,117 2025 9,117 2026 9,117 2027 8,832
Schedule of Earnings Per Share, Basic and Diluted Reconciliation	The following table sets forth the weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated: Successor Predecessor Year Ended Year Ended Period from Period from In thousands Weighted average common shares outstanding – basic 51,427 50,918 50,000 495,560 Effect of potentially dilutive securities Restricted stock, restricted stock units and performance stock units 622 762 — — Warrants 2,306 2,138 — — Weighted average common shares outstanding – diluted 54,355 53,818 50,000 495,560
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following outstanding securities were excluded from the computation of diluted net income (loss) per share for the year ended December 31, 2022, year ended December 31, 2021, and the period September 19, 2020 through December 31, 2020, as their effect would have been antidilutive, as of the respective dates: In thousands December 31, 2022 December 31, 2021 December 31, 2020 Restricted stock, restricted stock units and performance stock units 11 — 1,220 Warrants — — 5,526 Employee Stock Purchase Plan — — —

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2022
Reorganizations [Abstract]
Schedule of 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: 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 Debtor-in-possession 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.

Acquisition and Divestitures (T

Acquisition and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Schedule of Fair Value of Assets Acquired and Liabilities Assumed	The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition: In thousands Consideration: Cash consideration $ 10,906 Fair value of assets acquired and liabilities assumed: Proved oil and natural gas properties 60,101 Other property and equipment 1,685 Asset retirement obligations (39,794) Contingent consideration (5,320) Other liabilities (5,766) Fair value of net assets acquired $ 10,906

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The following table summarizes our revenues by product type: Successor Predecessor Year Ended Year Ended Period from Period from In thousands Oil sales $ 1,559,111 $ 1,148,022 $ 199,769 $ 489,251 Natural gas sales 19,571 11,933 1,339 2,850 CO 2 sales and transportation fees 60,570 44,175 9,419 21,049 Oil marketing revenues 65,093 38,742 5,376 8,543 Total revenues $ 1,704,345 $ 1,242,872 $ 215,903 $ 521,693

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
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: In thousands December 31, 2022 December 31, 2021 Operating leases Operating lease right-of-use assets $ 18,017 $ 19,502 Operating lease liabilities – current $ 4,676 $ 4,677 Operating lease liabilities – long-term 15,431 17,094 Total operating lease liabilities $ 20,107 $ 21,771
Schedule of Weighted Average Lease Terms and Discount Rates	The following table presents weighted average remaining lease terms and discount rates for our outstanding operating leases: December 31, 2022 December 31, 2021 Weighted average remaining lease term 4.5 years 5.2 years Weighted average discount rate 5.7 % 5.4 %
Schedule of Lease Costs	The following table summarizes the components of lease costs and sublease income: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Income Statement Operating lease cost General and administrative expenses $ 5,532 $ 4,102 $ 872 $ 5,683 Lease operating expenses 178 655 158 214 CO 2 operating and discovery expenses 50 50 14 37 $ 5,760 $ 4,807 $ 1,044 $ 5,934 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ — $ — $ 3 $ 9 Interest on lease liabilities Interest expense — — 1 3 Total finance lease cost $ — $ — $ 4 $ 12 Variable lease cost $ 758 $ 670 $ 258 $ 3,688 Sublease income General and administrative expenses $ — $ — $ 100 $ 2,584
Schedule of 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 Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 5,903 $ 2,830 $ 341 $ 7,341 Operating cash flows from interest on finance leases — — 1 3 Financing cash flows from finance leases — — 78 10 Right-of-use assets obtained in exchange for lease obligations Operating leases 2,270 2,683 19,902 1,049 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, 2022: Operating In thousands Leases 2023 $ 5,702 2024 4,963 2025 4,974 2026 4,640 2027 1,786 Thereafter 1,023 Total minimum lease payments 23,088 Less: Amount representing interest (2,981) Present value of minimum lease liabilities $ 20,107

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	The following table summarizes the changes in our asset retirement obligations: Year Ended Year Ended Dec. 31, 2021 In thousands Beginning asset retirement obligations $ 302,611 $ 186,281 Liabilities incurred and assumed during period 547 43,701 Revisions in estimated retirement obligations 64,667 69,059 Liabilities settled and sold during period (34,260) (10,783) Accretion expense 18,477 14,353 Ending asset retirement obligations 352,042 302,611 Less: current asset retirement obligations (1) (36,100) (18,373) Long-term asset retirement obligations $ 315,942 $ 284,238 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Unevaluated Property (Tables)

Unevaluated Property (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Schedule of Unevaluated Properties Excluded from Amortization	A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2022, and the year in which the costs were incurred follows: December 31, 2022 Costs Incurred During: In thousands 2022 2021 Successor 2020 Fresh Start Adjustments (Sept. 18, 2020) (1) Total Property acquisition costs $ — $ — $ — $ 64,077 $ 64,077 Exploration and development 132,494 35,881 — — 168,375 Capitalized interest 3,824 3,575 584 — 7,983 Total $ 136,318 $ 39,456 $ 584 $ 64,077 $ 240,435 (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, 2022.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Income Tax Provision (Benefit)	Our income tax provision (benefit) is as follows: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Current income tax expense (benefit) Federal $ 3,055 $ — $ — $ (6,407) State 2,308 403 30 (853) Total current income tax expense (benefit) 5,363 403 30 (7,260) Deferred income tax expense (benefit) Federal 63,814 — — (319,011) State 5,667 364 (2,556) (89,858) Total deferred income tax expense (benefit) 69,481 364 (2,556) (408,869) Total income tax expense (benefit) $ 74,844 $ 767 $ (2,526) $ (416,129)
Schedule of Deferred Tax Assets and Liabilities	Significant components of our deferred tax assets and liabilities as of December 31, 2022 and 2021 are as follows: In thousands December 31, 2022 December 31, 2021 Deferred tax assets Loss and tax credit carryforwards – state $ 48,172 $ 54,943 Derivative contracts — 30,892 Accrued liabilities and other reserves 19,155 19,567 Business credit carryforwards 10,487 18,066 Loss carryforwards – federal — 10,310 Lease liabilities 1,998 4,523 Property and equipment — 2,613 Other 5,974 4,206 Valuation allowances (59,233) (125,462) Total deferred tax assets 26,553 19,658 Deferred tax liabilities Property and equipment (78,055) — CO 2 and other contracts (15,304) (17,208) Operating lease right-of-use assets (2,770) (4,088) Derivative contracts (1,544) — Total deferred tax liabilities (97,673) (21,296) Total net deferred tax liability $ (71,120) $ (1,638)
Schedule of 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 Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Income tax provision calculated using the federal statutory income tax rate $ 116,551 $ 11,921 $ (11,169) $ (388,228) State income taxes 20,642 1,468 8,509 (120,340) Tax windfall on stock-based compensation deduction (158) (267) — (1,380) Nondeductible compensation 2,303 5,057 — — Change in valuation allowance (66,229) (3,946) (432) 52,625 EOR and other (1,530) (14,272) — — Tax attributes reduction – net of cancellation of indebtedness income exclusion — — — 31,667 Other 3,265 806 566 9,527 Total income tax expense (benefit) $ 74,844 $ 767 $ (2,526) $ (416,129)
Tax Valuation Allowance
Valuation Allowance [Line Items]
Schedule of Changes in Valuation Allowance	The changes in our valuation allowance are detailed below: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Beginning balance $ 125,462 $ 129,408 $ 129,840 $ 77,215 Charges 790 29,345 2,269 77,138 Deductions (67,019) (33,291) (2,701) (24,513) Ending balance $ 59,233 $ 125,462 $ 129,408 $ 129,840

Stock Compensation (Tables)

Stock Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
Stock Compensation
Schedule of Stock-Based Compensation Costs	The following table sets forth stock-based compensation costs for the periods indicated: Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Stock-based compensation expense included in G&A $ 16,055 $ 25,322 $ 8,212 $ 4,111 Stock-based compensation capitalized 1,012 1,883 695 1,660 Total cost of stock-based compensation arrangements $ 17,067 $ 27,205 $ 8,907 $ 5,771 Income tax benefit recognized for stock-based compensation arrangements $ 1,663 $ 1,846 $ 2,053 $ 1,028
Restricted Stock Units
Stock Compensation
Schedule of 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 and the weighted average grant-date fair value of restricted stock granted of units and awards: Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 In thousands, except weighted-average grant-date fair value Fair value of restricted stock units vested $ 36,047 $ 31,073 $ — Weighted-average grant-date fair value of restricted stock units granted during year 76.08 31.87 24.67 Fair value of restricted stock awards vested $ 6 $ — $ — Weighted-average grant-date fair value of restricted stock awards granted during year 76.87 — —
Schedule of Nonvested Restricted Stock Units Activity	A summary of the status of our non-performance-based RSUs and restricted stock awards issued and the changes during the year ended December 31, 2022 (Successor) period is presented below: Restricted Stock Units Number Weighted Nonvested at December 31, 2021 849,907 $ 25.08 Granted 15,893 76.08 Vested (412,065) 25.05 Forfeited (23,842) 24.67 Nonvested at December 31, 2022 429,893 27.02 Restricted Stock Awards Number Weighted Nonvested at December 31, 2021 — $ — Granted 158,692 76.87 Vested (98) 76.08 Forfeited (5,737) 76.08 Nonvested at December 31, 2022 152,857 76.90
Performance Share Units
Stock Compensation
Schedule of Total Vesting Date Fair Value of Equity Awards	The following is a summary of the total vesting date fair value and weighted average grant-date fair value of PSU awards: Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 In thousands, except weighted average grant date fair value Fair value of performance stock units vested $ — 45,077 — Weighted-average grant-date fair value of performance stock units granted during year 89.43 — 24.19
Schedule of Performance-Based Equity Awards Valuation Assumptions	The range of assumptions used in the Monte Carlo simulation valuation approach is as follows: Successor Year Ended Period from Sept. 19, 2020 through Dec. 31, 2020 Weighted average fair value of PSU awards granted $ 89.43 $ 24.19 Weighted average risk-free interest rate 1.76 % 0.21 % Expected life 2.96 years 0.23 years Weighted average expected volatility 61.6 % 110.0 % Dividend yield — % — %
Schedule of Nonvested Performance Stock Unit Awards Activity	A summary of the PSU awards activity during the year ended December 31, 2022 (Successor) is as follows: Number Weighted Nonvested at December 31, 2021 — $ — Granted 110,385 89.43 Vested — — Forfeited (4,273) 90.86 Nonvested at December 31, 2022 106,112 89.37
Restricted Stock
Stock Compensation
Schedule of 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: Period from Jan. 1, 2020 through Sept. 18, 2020 In thousands Fair value of restricted stock vested $ 707
Performance-Based Equity Awards
Stock Compensation
Schedule of 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: Period from Jan. 1, 2020 through Sept. 18, 2020 In thousands Fair value of Performance-Based TSR awards vested 79
Schedule 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: Period from Jan. 1, 2020 through Sept. 18, 2020 Weighted average fair value of Performance-Based TSR Awards granted $ 0.15 Risk-free interest rate 0.27 % Expected life 3.0 years Expected volatility 89.6 % Dividend yield — %

Commodity Derivative Contracts

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Commodity Derivative Contracts not Classified as Hedging Instruments	The following table summarizes our commodity derivative contracts as of December 31, 2022, 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) Weighted Average Price Swap Floor Ceiling Oil Contracts: 2023 Fixed-Price Swaps Jan – Jun NYMEX 9,500 $ 76.65 $ — $ — July – Dec NYMEX 11,000 78.48 — — 2023 Collars Jan – Jun NYMEX 17,500 $ — $ 69.71 $ 100.42 July – Dec NYMEX 9,000 — 68.33 100.69

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of 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, 2022 and 2021: Fair Value Measurements Using: Quoted Prices Significant Significant In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2022 Assets Oil derivative contracts – current $ — $ 15,517 $ — $ 15,517 Oil derivative contracts – long-term — — — — Total Assets $ — $ 15,517 $ — $ 15,517 Liabilities Oil derivative contracts – current $ — $ (13,018) $ — $ (13,018) Oil derivative contracts – long-term — — — — Total Liabilities $ — $ (13,018) $ — $ (13,018) December 31, 2021 Liabilities Oil derivative contracts – current $ — $ (134,509) $ — $ (134,509) Oil derivative contracts – long-term — — — — Total Liabilities $ — $ (134,509) $ — $ (134,509)

Additional Balance Sheet Deta_2

Additional Balance Sheet Details (Tables)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Trade and Other Receivables, Net	Trade and Other Receivables, Net In thousands December 31, 2022 December 31, 2021 Trade accounts receivable, net $ 19,619 $ 10,832 Federal income tax receivable, net 597 597 Other receivables 7,127 7,841 Total $ 27,343 $ 19,270
Schedule of Allowance for Doubtful Accounts	Rollforward of Allowance for Doubtful Accounts Successor Predecessor Year Ended Year Ended Period from Period from In thousands Beginning balance $ 18,947 $ 23,206 $ 22,146 $ 17,137 Provision for doubtful accounts 1,270 826 1,060 5,297 Write-offs — (5,085) — (288) Ending balance $ 20,217 $ 18,947 $ 23,206 $ 22,146
Schedule of Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities In thousands December 31, 2022 December 31, 2021 Accounts payable $ 58,905 $ 25,700 Accrued asset retirement obligations – current 36,100 18,373 Accrued lease operating expenses 29,454 27,901 Accrued exploration and development costs 28,963 18,936 Accrued compensation 27,025 23,735 Taxes payable 19,487 14,453 Accrued derivative settlements 9,452 27,336 Other 39,414 35,164 Total $ 248,800 $ 191,598

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Schedule of Supplemental Cash Flow Information	Supplemental Cash Flow Information Successor Predecessor Year Ended Year Ended Dec. 31, 2021 Period from Sept. 19, 2020 through Dec. 31, 2020 Period from In thousands Supplemental cash flow information Cash paid for interest, expensed $ 1,961 $ 4,227 $ 813 $ 29,357 Cash paid for interest, capitalized 4,237 4,585 1,261 22,885 Cash paid for interest, treated as a reduction of debt — — — 46,417 Cash paid for income taxes 7,543 184 — 453 Cash received from income tax refunds 3 3 10,457 1,932 Noncash investing and financing activities Increase in asset retirement obligations 65,214 112,760 23,398 4,328 Increase (decrease) in liabilities for capital expenditures 27,271 35,679 1,867 (12,809) Conversion of convertible senior notes into common stock — — — 11,501

Nature of Operations and Summ_4

Nature of Operations and Summary of Significant Accounting Policies - Plan of Reorganization (Details) - USD ($)	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Plan of Chapter 11 Reorganization [Line Items]
Principal amount of debt cancelled	$ 2,100,000,000
Successor common stock, shares authorized (in shares)	250,000,000	250,000,000	250,000,000
Successor common stock, par value (in dollars per share)	$ 0.001	$ 0.001	$ 0.001
Successor preferred stock, shares authorized (in shares)	50,000,000	50,000,000	50,000,000
Successor preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001	$ 0.001
Number of warrants outstanding (in shares)		3,200,000
Lender commitments	$ 575,000,000
Series A Warrants
Plan of Chapter 11 Reorganization [Line Items]
Number of warrants outstanding (in shares)	2,631,579	1,800,000
Exercise price of warrants (in dollars per share)	$ 32.59	$ 32.59
Series B Warrants
Plan of Chapter 11 Reorganization [Line Items]
Number of warrants outstanding (in shares)	2,894,740	1,400,000
Exercise price of warrants (in dollars per share)	$ 35.41	$ 35.41
Second Lien Note Holders
Plan of Chapter 11 Reorganization [Line Items]
Common stock, shares outstanding (in shares)	47,499,999
Equity percentage under plan of reorganization (as a percent)	95%
Convertible Note Holders
Plan of Chapter 11 Reorganization [Line Items]
Common stock, shares outstanding (in shares)	2,500,000
Equity percentage under plan of reorganization (as a percent)	5%
Convertible Note Holders | Series A Warrants
Plan of Chapter 11 Reorganization [Line Items]
Percentage of warrants	100%
Convertible Note Holders | Series A Warrants | Maximum
Plan of Chapter 11 Reorganization [Line Items]
Equity percentage under plan of reorganization (as a percent)	5%
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 (as a percent)	3%
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 (as a percent)	2.50%

Nature of Operations and Summ_5

Nature of Operations and Summary of Significant Accounting Policies - Narrative (Details)		3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 18, 2020 $ / Barrel	Dec. 31, 2020 USD ($)	Sep. 18, 2020 USD ($)	Dec. 31, 2022 USD ($) segment $ / Barrel	Dec. 31, 2021 USD ($) $ / Barrel	Dec. 31, 2020 $ / Barrel
Property, Plant and Equipment [Line Items]
Number of reporting segments | segment				1
CCUS storage sites and related assets				$ 64,971,000	$ 0
CCUS storage sites and related capital expenditures		$ 0	$ 0	$ (59,880,000)	$ 0
Impairments of unevaluated costs			244,900,000
Oil and gas, average sale price (in dollars per unit) | $ / Barrel	40.08			93.02	63.86	35.84
Ceiling test write-downs of oil and gas properties		1,006,000	996,658,000	$ 0	$ 14,377,000
Amortization of intangible assets		2,700,000	1,700,000	9,100,000	9,100,000
Equity investment		0	0	10,218,000	0
Impairment of long-lived assets		$ 0	$ 0	0	$ 0
Project Development Company Of Planned Louisiana Blue Hydrogen Ammonia Project
Property, Plant and Equipment [Line Items]
Equity investment				10,000,000
Project Development Company Of Planned Louisiana Blue Hydrogen Ammonia Project | Investment Commitment
Property, Plant and Equipment [Line Items]
Committed to invest, on certain milestone achieved				10,000,000
CCUS Business
Property, Plant and Equipment [Line Items]
CCUS storage sites and related assets				65,000,000
CCUS storage sites and related capital expenditures				$ 59,900,000
Minimum
Property, Plant and Equipment [Line Items]
Useful life of intangible CO2 contracts				7 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life of intangible CO2 contracts				14 years
Pipelines | Minimum
Property, Plant and Equipment [Line Items]
Useful life				20 years
Pipelines | Maximum
Property, Plant and Equipment [Line Items]
Useful life				50 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Useful life				5 years
Furniture and Fixtures | Maximum
Property, Plant and Equipment [Line Items]
Useful life				10 years
Computer Equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful life				3 years
Computer Equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful life				5 years

Nature of Operations and Summ_6

Nature of Operations and Summary of Significant Accounting Policies - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Cash and cash equivalents	$ 521	$ 3,671		$ 45,585
Restricted cash for future asset retirement obligations	47,359	46,673
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 47,880	$ 50,344	$ 42,248	$ 95,114	$ 33,045

Nature of Operations and Summ_7

Nature of Operations and Summary of Significant Accounting Policies - Carrying Value of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Long-term contracts to sell CO2 to industrial customers	$ 97,943	$ 97,943
Other intangibles	2,179	2,179
Accumulated amortization	(20,994)	(11,874)
Net book value	$ 79,128	$ 88,248

Nature of Operations and Summ_8

Nature of Operations and Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangibles (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Accounting Policies [Abstract]
2023	$ 9,117
2024	9,117
2025	9,117
2026	9,117
2027	$ 8,832

Nature of Operations and Summ_9

Nature of Operations and Summary of Significant Accounting Policies - Concentrations of Credit Risk (Details) - Revenue Benchmark - Customer Concentration Risk	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Plains Marketing LP
Product Information [Line Items]
Revenue from major customer (as a percent)	30%	30%	27%	28%
Hunt Crude Oil Company
Product Information [Line Items]
Revenue from major customer (as a percent)	12%	12%	11%	12%
Marathon Petroleum Company
Product Information [Line Items]
Revenue from major customer (as a percent)	13%	12%		11%
Sunoco Inc
Product Information [Line Items]
Revenue from major customer (as a percent)				11%

Nature of Operations and Sum_10

Nature of Operations and Summary of Significant Accounting Policies - Net Income (Loss) per Common Share (Details) - $ / shares	3 Months Ended	9 Months Ended	12 Months Ended		27 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted average common shares outstanding – basic (in shares)	50,000,000	495,560,000	51,427,000	50,918,000
Weighted average number of dilutive shares (in shares)	50,000,000	495,560,000	54,355,000	53,818,000
Number of warrants outstanding (in shares)			3,200,000		3,200,000
Issued pursuant to exercise of warrants (in shares)					1,300,000
Series A Warrants
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Number of warrants outstanding (in shares)		2,631,579	1,800,000		1,800,000
Exercise price of warrants (in dollars per share)		$ 32.59	$ 32.59		$ 32.59
Number of warrants exercised (in shares)			800,000		800,000
Series B Warrants
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Number of warrants outstanding (in shares)		2,894,740	1,400,000		1,400,000
Exercise price of warrants (in dollars per share)		$ 35.41	$ 35.41		$ 35.41
Number of warrants exercised (in shares)			1,400,000		1,400,000
Net Income Scenario
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted average number of dilutive shares (in shares)	50,000,000	584,400,000
Performance-based and restricted stock units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted average common shares outstanding – basic (in shares)			1,784,474

Nature of Operations and Sum_11

Nature of Operations and Summary of Significant Accounting Policies - Reconciliation of Weighted Average Shares (Details) - shares shares in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Weighted average common shares outstanding – basic (in shares)	50,000	495,560	51,427	50,918
Restricted stock, restricted stock units and performance stock units (in shares)	0	0	622	762
Warrants (in shares)	0	0	2,306	2,138
Weighted average common shares outstanding – diluted (in shares)	50,000	495,560	54,355	53,818

Nature of Operations and Sum_12

Nature of Operations and Summary of Significant Accounting Policies - Antidilutive Securities (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restricted stock, restricted stock units and performance stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share
Number of antidilutive equity-based instruments outstanding (in shares)	11	0	1,220
Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share
Number of antidilutive equity-based instruments outstanding (in shares)	0	0	5,526
Employee Stock Purchase Plan
Antidilutive Securities Excluded from Computation of Earnings Per Share
Number of antidilutive equity-based instruments outstanding (in shares)	0	0	0

Fresh Start Accounting - Narrat

Fresh Start Accounting - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands		2 Months Ended	9 Months Ended
	Sep. 18, 2020	Sep. 18, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
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
Capitalized costs of proved and unproved properties	$ 865,400	865,400	865,400
Expected annual dividend yield for warrants (as a percent)	0%
Stockholders' equity, period increase (decrease)	$ 4,600		(5,331)
Decrease to deferred taxes	128,600	128,600	128,600
Deferred tax liabilities, net	3,831	3,831	3,831	$ 71,120	$ 1,638
Fresh Start Adjustments
Reorganization Value [Line Items]
Deferred tax liabilities, net	$ (414,120)	$ (414,120)	$ (414,120)
Series A Warrants
Reorganization Value [Line Items]
Exercise price of warrants (in dollars per share)	$ 32.59	$ 32.59	$ 32.59	$ 32.59
Expected volatility of warrants (as a percent)	49.30%
Risk free interest rate associated with warrants (as a percent)	0.30%
Term of warrants (in years)	5 years	5 years	5 years
Series B Warrants
Reorganization Value [Line Items]
Exercise price of warrants (in dollars per share)	$ 35.41	$ 35.41	$ 35.41	$ 35.41
Expected volatility of warrants (as a percent)	53.60%
Risk free interest rate associated with warrants (as a percent)	0.20%
Term of warrants (in years)	3 years	3 years	3 years
Measurement Input, Share Price
Reorganization Value [Line Items]
Implied stock price (in dollars per share)	$ 22.14	$ 22.14	$ 22.14
Minimum
Reorganization Value [Line Items]
Enterprise value	$ 1,100,000	$ 1,100,000	$ 1,100,000
Maximum
Reorganization Value [Line Items]
Enterprise value	1,500,000	1,500,000	1,500,000
Median
Reorganization Value [Line Items]
Enterprise value	$ 1,300,000	$ 1,300,000	$ 1,300,000

Fresh Start Accounting - Enterp

Fresh Start Accounting - Enterprise Value to Equity Value (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019
Reorganizations [Abstract]
Enterprise value				$ 1,280,856
Plus: Cash and cash equivalents	$ 521	$ 3,671		45,585
Less: Total debt				(231,022)
Equity value	$ 1,532,617	$ 1,135,390	$ 1,053,668	$ 1,095,419	$ 1,412,259

Fresh Start Accounting - Reconc

Fresh Start Accounting - Reconciliation of Reorganization Value (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Reorganizations [Abstract]
Enterprise value			$ 1,280,856
Plus: Cash and cash equivalents	$ 521	$ 3,671	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 - Reorga

Fresh Start Accounting - Reorganization Items (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
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
Debtor-in-possession 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 - Consol

Fresh Start Accounting - Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2019
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents	$ 521	$ 3,671		$ 45,585
Restricted cash				10,662
Accrued production receivable				112,832
Trade and other receivables, net	27,343	19,270		36,221
Derivative assets	15,517	0		32,635
Prepaids	18,572	9,099		12,429
Total current assets	206,230	175,405		250,364
Proved properties	1,414,779	1,109,011		782,233
Unevaluated properties	240,435	112,169		111,983
CO2 properties	190,985	183,369		187,346
Pipelines	220,125	224,394		132,618
Other property and equipment	107,133	93,950		97,413
Less accumulated depletion, depreciation, amortization and impairment	(306,743)	(181,393)		0
Net property and equipment	1,931,685	1,541,500		1,311,593
Operating lease right-of-use assets	18,017	19,502		1,843
Derivative assets	0			501
Intangible assets, net				100,083
Other assets	45,080	31,625		87,023
Total assets	2,327,499	1,902,953		1,751,407
Accounts payable and accrued liabilities	248,800	191,598		174,320
Oil and gas production payable				56,077
Derivative liabilities	13,018	134,509		8,613
Current maturities of long-term debt				73,563
Operating lease liabilities	4,676	4,677		728
Total current liabilities	346,862	406,683		313,301
Long-term debt, net of current portion	29,000	35,000		157,459
Asset retirement obligations	315,942	284,238		158,438
Derivative liabilities	0	0		295
Deferred tax liabilities, net	71,120	1,638		3,831
Operating lease liabilities	15,431	17,094		525
Other liabilities	16,527	22,910		22,139
Total long-term liabilities not subject to compromise				342,687
Liabilities subject to compromise				2,823,506
Common stock	50	50		50
Paid-in capital in excess of par				1,095,369
Accumulated deficit	485,504	5,344
Total stockholders’ equity	1,532,617	1,135,390	$ 1,053,668	1,095,419	$ 1,412,259
Total liabilities and stockholders’ equity	$ 2,327,499	$ 1,902,953		1,751,407
Predecessor
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents				73,372
Accrued production receivable				112,832
Trade and other receivables, net				36,221
Derivative assets				32,635
Prepaids				12,968
Total current assets				268,028
Proved properties				11,723,546
Unevaluated properties				650,553
CO2 properties				1,198,515
Pipelines				2,339,864
Other property and equipment				201,565
Less accumulated depletion, depreciation, amortization and impairment				(12,864,141)
Net property and equipment				3,249,902
Operating lease right-of-use assets				1,774
Derivative assets				501
Intangible assets, net				20,405
Other assets				81,809
Total assets				3,622,419
Accounts payable and accrued liabilities				67,789
Oil and gas production payable				39,372
Derivative liabilities				8,613
Total current liabilities				115,774
Long-term debt, net of current portion				140,000
Asset retirement obligations				2,727
Derivative liabilities				295
Total long-term liabilities not subject to compromise				143,022
Liabilities subject to compromise				2,823,506
Common stock				510
Paid-in capital in excess of par				2,764,915
Treasury stock, at cost				(6,202)
Accumulated deficit				(2,219,106)
Total stockholders’ equity				540,117
Total liabilities and stockholders’ equity				3,622,419
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents				(27,787)
Restricted cash				10,662
Prepaids				(539)
Total current assets				(17,664)
Other assets				8,241
Total assets				(9,423)
Accounts payable and accrued liabilities				102,793
Oil and gas production payable				16,705
Current maturities of long-term debt				73,199
Operating lease liabilities				757
Total current liabilities				193,454
Long-term debt, net of current portion				42,610
Asset retirement obligations				180,408
Deferred tax liabilities, net				417,951
Operating lease liabilities				515
Other liabilities				3,540
Total long-term liabilities not subject to compromise				645,024
Liabilities subject to compromise				(2,823,506)
Accumulated deficit				3,639,409
Total stockholders’ equity				1,975,605
Total liabilities and stockholders’ equity				(9,423)
Reorganization Adjustments | Predecessor Adjustment
Fresh-Start Adjustment [Line Items]
Common stock				(510)
Paid-in capital in excess of par				(2,764,915)
Treasury stock, at cost				6,202
Reorganization Adjustments | Successor Adjustment
Fresh-Start Adjustment [Line Items]
Common stock				50
Paid-in capital in excess of par				1,095,369
Fresh Start Adjustments
Fresh-Start Adjustment [Line Items]
Proved properties				(10,941,313)
Unevaluated properties				(538,570)
CO2 properties				(1,011,169)
Pipelines				(2,207,246)
Other property and equipment				(104,152)
Less accumulated depletion, depreciation, amortization and impairment				12,864,141
Net property and equipment				(1,938,309)
Operating lease right-of-use assets				69
Intangible assets, net				79,678
Other assets				(3,027)
Total assets				(1,861,589)
Accounts payable and accrued liabilities				3,738
Current maturities of long-term debt				364
Operating lease liabilities				(29)
Total current liabilities				4,073
Long-term debt, net of current portion				(25,151)
Asset retirement obligations				(24,697)
Deferred tax liabilities, net				(414,120)
Operating lease liabilities				10
Other liabilities				18,599
Total long-term liabilities not subject to compromise				(445,359)
Accumulated deficit				(1,420,303)
Total stockholders’ equity				(1,420,303)
Total liabilities and stockholders’ equity				$ (1,861,589)

Fresh Start Accounting - Net Ca

Fresh Start Accounting - Net Cash Payments (Details) $ in Thousands	9 Months Ended
	Sep. 18, 2020 USD ($)
Reorganizations [Abstract]
Cash proceeds from Successor Bank Credit Agreement	$ 140,000
Total cash proceeds	140,000
Payment in full 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)

Fresh Start Accounting - Accoun

Fresh Start Accounting - Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Fresh-Start Adjustment [Line Items]
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	$ 248,800	$ 191,598	174,320
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Accounts payable and accrued liabilities			$ 102,793

Fresh Start Accounting - Liabil

Fresh Start Accounting - Liabilities Subject to Compromise (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Reorganization Value [Line Items]
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			73,563
Accounts payable and accrued liabilities			101,431
Oil and gas production payable			56,077
Operating lease liabilities, current	$ 4,676	$ 4,677	728
Long-term debt, net of current portion	29,000	35,000	157,459
Asset retirement obligations	315,942	284,238	158,438
Deferred tax liabilities			289,389
Operating lease liabilities, long-term	15,431	17,094	525
Other long-term liabilities	$ 16,527	$ 22,910	22,139
Total reinstated liabilities subject to compromise			708,554
Total liabilities subject to compromise			2,823,506
Issuance of New Common Stock to second lien note holders			(1,014,608)
Issuance of New Common Stock to convertible note holders			(53,400)
Issuance of series A warrants to convertible note holders			(15,683)
Issuance of series B warrants to senior subordinated note holders			(6,398)
Reinstatement of liabilities subject to compromise			(708,553)
Gain on settlement of liabilities subject to compromise			1,024,864
Reorganization Adjustments
Reorganization Value [Line Items]
Current maturities of long-term debt			73,199
Oil and gas production payable			16,705
Operating lease liabilities, current			757
Long-term debt, net of current portion			42,610
Asset retirement obligations			180,408
Operating lease liabilities, long-term			515
Other long-term liabilities			3,540
Total liabilities subject to compromise			$ (2,823,506)

Fresh Start Accounting - Succes

Fresh Start Accounting - Successor's Common Stock and Additional Paid-In Capital (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Fresh-Start Adjustment [Line Items]
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
Par value of common stock	$ 50	$ 50	50
Change in Successor additional paid-in capital			$ 1,095,369
Common stock, shares issued (in shares)	49,814,874	50,193,656
New Common Stock Issued to Holders of Senior Secured Second Lien Note
Fresh-Start Adjustment [Line Items]
Common stock, shares issued (in shares)			47,499,999
Common stock, shares outstanding (in shares)			47,499,999
New Common Stock Issued to Holders of Convertible Senior Note
Fresh-Start Adjustment [Line Items]
Common stock, shares issued (in shares)			2,500,000
Common stock, shares outstanding (in shares)			2,500,000

Fresh Start Accounting - Accumu

Fresh Start Accounting - Accumulated Deficit Adjustments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Fresh-Start Adjustment [Line Items]
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	$ 485,504	$ 5,344
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Net impact to Predecessor accumulated deficit			$ 3,639,409

Fresh Start Accounting - Fair V

Fresh Start Accounting - Fair Value Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Fresh-Start Adjustment [Line Items]
Fair value adjustment for CO2 and oil pipeline line-fill			$ (3,698)
Fair value adjustments for escrow accounts			671
Fair value adjustments to other assets	$ 45,080	$ 31,625	87,023
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) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
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)
Accounts payable and accrued liabilities	$ 248,800	$ 191,598	174,320
Fresh Start Adjustments
Fresh-Start Adjustment [Line Items]
Accounts payable and accrued liabilities			$ 3,738

Fresh Start Accounting - Debt A

Fresh Start Accounting - Debt Adjustments (Details) $ in Thousands	Sep. 18, 2020 USD ($)
Reorganizations [Abstract]
Fair value adjustment for Free State pipeline lease financing	$ (24,699)
Fair value adjustment for NEJD pipeline lease financing	(88)
Fair value adjustments to current and long-term maturities of debt	$ (24,787)

Acquisition and Divestitures -

Acquisition and Divestitures - Narrative (Details)					3 Months Ended	6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($)	Mar. 03, 2021 USD ($) payment	Sep. 18, 2020 $ / Barrel	Mar. 04, 2020 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 18, 2020 USD ($)	Dec. 31, 2022 USD ($) $ / Barrel	Dec. 31, 2021 USD ($) $ / Barrel	Dec. 31, 2020 $ / Barrel
Business Acquisition, Contingent Consideration [Line Items]
Average oil price (in usd per barrel) | $ / Barrel			40.08						93.02	63.86	35.84
Net proceeds from sales of oil and natural gas properties and equipment	$ 18,000,000			$ 40,000,000	$ 938,000			$ 41,322,000	$ 237,000	$ 19,053,000
Gain (loss) on disposition of oil and natural gas properties	$ 0			$ 0
Gross proceeds from land sales						$ 1,400,000	$ 15,200,000
Gain from asset sales and other (in usd per barrel)					$ 3,546,000	800,000	$ 10,300,000	$ 6,723,000	1,232,000	10,609,000
Big Sand Draw and Beaver Creek Fields
Business Acquisition, Contingent Consideration [Line Items]
Approximate working interest percentage acquired		100%
Approximate net revenue interest percentage acquired		83%
Cash consideration for acquisition of oil and natural gas properties		$ 10,906,000
Number of contingent cash payments | payment		2
Contingent cash payment		$ 4,000,000
Contingent consideration at acquisition date		$ 5,320,000
Fair value of contingent consideration						$ 4,000,000			4,000,000
Increase in contingent consideration									$ 300,000	$ 2,400,000
Big Sand Draw and Beaver Creek Fields | Minimum
Business Acquisition, Contingent Consideration [Line Items]
Average oil price (in usd per barrel) | $ / Barrel									50

Acquisition and Divestitures _2

Acquisition and Divestitures - Fair Value of Assets Acquired and Liabilities Assumed (Details) - Big Sand Draw and Beaver Creek Fields $ in Thousands	Mar. 03, 2021 USD ($)
Business Acquisition [Line Items]
Cash consideration	$ 10,906
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	60,101
Other property and equipment	1,685
Asset retirement obligations	(39,794)
Contingent consideration	(5,320)
Other liabilities	(5,766)
Fair value of net assets acquired	$ 10,906

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue
Revenues	$ 215,903	$ 521,693	$ 1,704,345	$ 1,242,872
Oil sales
Disaggregation of Revenue
Revenues	199,769	489,251	1,559,111	1,148,022
Natural gas sales
Disaggregation of Revenue
Revenues	1,339	2,850	19,571	11,933
CO2 sales and transportation fees
Disaggregation of Revenue
Revenues	9,419	21,049	60,570	44,175
Oil marketing revenues
Disaggregation of Revenue
Revenues	$ 5,376	$ 8,543	$ 65,093	$ 38,742

Leases - Narrative (Details)

Leases - Narrative (Details) - Maximum	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Remaining lease term (in years)	13 years
Land
Lessee, Lease, Description [Line Items]
Remaining lease term (in years)	47 years

Leases - Lease Assets and Liabi

Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Leases, Operating [Abstract]
Operating lease right-of-use assets	$ 18,017	$ 19,502	$ 1,843
Operating lease liabilities – current	4,676	4,677	728
Operating lease liabilities – long-term	15,431	17,094	$ 525
Total operating lease liabilities	$ 20,107	$ 21,771

Leases - Weighted Average Lease

Leases - Weighted Average Lease Terms and Discount Rates (Details)	Dec. 31, 2022 Rate	Dec. 31, 2021 Rate
Leases [Abstract]
Weighted average remaining lease term (in years)	4 years 6 months	5 years 2 months 12 days
Weighted average discount rate (as a percent)	5.70%	5.40%

Leases - Lease Costs (Details)

Leases - Lease Costs (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Lease Cost [Line Items]
Operating lease cost	$ 1,044	$ 5,934	$ 5,760	$ 4,807
Finance lease cost
Amortization of right-of-use assets	3	9	0	0
Interest on lease liabilities	1	3	0	0
Total finance lease cost	4	12	0	0
Variable lease cost	258	3,688	758	670
Sublease income	100	2,584	0	0
General and administrative expenses
Lease Cost [Line Items]
Operating lease cost	872	5,683	5,532	4,102
Lease operating expenses
Lease Cost [Line Items]
Operating lease cost	158	214	178	655
CO2 operating and discovery expenses | CO2 sales and transportation fees
Lease Cost [Line Items]
Operating lease cost	$ 14	$ 37	$ 50	$ 50

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 341	$ 7,341	$ 5,903	$ 2,830
Operating cash flows from interest on finance leases	1	3	0	0
Financing cash flows from finance leases	78	10	0	0
Right-of-use assets obtained in exchange for lease obligations
Operating leases	19,902	1,049	2,270	2,683
Finance leases	$ 0	$ 162	$ 0	$ 0

Leases - Maturities of Lease Li

Leases - Maturities of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
2023	$ 5,702
2024	4,963
2025	4,974
2026	4,640
2027	1,786
Thereafter	1,023
Total minimum lease payments	23,088
Less: Amount representing interest	(2,981)
Present value of minimum lease liabilities	$ 20,107	$ 21,771

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Asset Retirement Obligation Roll Forward [Roll Forward]
Beginning asset retirement obligations	$ 302,611	$ 186,281
Liabilities incurred and assumed during period	547	43,701
Revisions in estimated retirement obligations	64,667	69,059
Liabilities settled and sold during period	(34,260)	(10,783)
Accretion expense	18,477	14,353
Ending asset retirement obligations	352,042	302,611
Less: current asset retirement obligations	(36,100)	(18,373)
Long-term asset retirement obligations	$ 315,942	$ 284,238	$ 158,438

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Balance in escrow accounts	$ 55.9	$ 55.6

Unevaluated Property - Unevalua

Unevaluated Property - Unevaluated Properties Excluded from Amortization (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
	Sep. 18, 2020	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Summary of unevaluated properties excluded from oil and natural gas properties being amortized
Property acquisition costs	$ 64,077	$ 0	$ 0	$ 0
Exploration and development	0	0	132,494	35,881
Capitalized interest	0	584	3,824	3,575
Total	64,077	$ 584	136,318	39,456
Property acquisition costs			64,077
Exploration and development			168,375
Capitalized interest			7,983
Total	$ 111,983		$ 240,435	$ 112,169

Unevaluated Property - Narrativ

Unevaluated Property - Narrative (Details)	12 Months Ended
	Dec. 31, 2022
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 (Details)

Long-Term Debt (Details) - USD ($)		4 Months Ended	8 Months Ended	12 Months Ended
	Oct. 30, 2020	May 03, 2022	Dec. 31, 2022	Dec. 31, 2022	May 04, 2022	Dec. 31, 2021	Sep. 18, 2020
Debt Instrument [Line Items]
Interest in guarantor subsidiaries			100%	100%
Borrowing base		$ 575,000,000			$ 750,000,000		$ 575,000,000
Commitment fee percentage				0.50%
Long-term line of credit			$ 29,000,000	$ 29,000,000		$ 35,000,000
Letter of credit			10,100,000	$ 10,100,000
Current ratio requirement				1
Weighted average interest rate				9%
Lease period included in long-term transportation service agreement				20 years
Unamortized debt issuance costs			9,200,000	$ 9,200,000		5,700,000
Total indebtedness			$ 29,000,000	29,000,000		$ 35,000,000	157,459,000
NEJD Pipeline
Debt Instrument [Line Items]
Payments to reacquire pipeline				$ 70,000,000
Free State Pipeline
Debt Instrument [Line Items]
Payments to reacquire pipeline	$ 22,500,000
Minimum | Base Rate
Debt Instrument [Line Items]
Interest rate margins on senior secured bank credit facility		2%	1.50%
Minimum | Secured Overnight Financing Rate ("SOFR")
Debt Instrument [Line Items]
Interest rate margins on senior secured bank credit facility			2.50%
Maximum
Debt Instrument [Line Items]
Consolidated total debt to consolidated EBITDAX requirement				3.5
Maximum | Base Rate
Debt Instrument [Line Items]
Interest rate margins on senior secured bank credit facility		3%	2.50%
Maximum | Secured Overnight Financing Rate ("SOFR")
Debt Instrument [Line Items]
Interest rate margins on senior secured bank credit facility			3.50%
Dividend or Other Restricted Payment | Minimum
Debt Instrument [Line Items]
Borrowing base availability requirement (as percent)					20%
Dividend or Other Restricted Payment | Maximum
Debt Instrument [Line Items]
Total debt to EBITDAX			1.5
Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, capacity available for specific purpose other than for trade purchases							100,000,000
Swingline Loan
Debt Instrument [Line Items]
Line of credit facility, capacity available for specific purpose other than for trade purchases							$ 25,000,000

Income Taxes - Income Tax Provi

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, 2022	Dec. 31, 2021
Current income tax expense (benefit)
Federal	$ 0	$ (6,407)	$ 3,055	$ 0
State	30	(853)	2,308	403
Total current income tax expense (benefit)	30	(7,260)	5,363	403
Deferred income tax expense (benefit)
Federal	0	(319,011)	63,814	0
State	(2,556)	(89,858)	5,667	364
Total deferred income tax expense (benefit)	(2,556)	(408,869)	69,481	364
Total income tax expense (benefit)	$ (2,526)	$ (416,129)	$ 74,844	$ 767

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Business credit carryforwards	$ 10,487,000	$ 18,066,000
Alternative minimum tax credits	600,000
Loss and tax credit carryforwards – state	48,172,000	$ 54,943,000
Income tax interest or penalties	0
Federal
Valuation Allowance [Line Items]
Valuation allowance, reversed	51,400,000
Certain State
Valuation Allowance [Line Items]
Valuation allowance, reversed	14,800,000
State deferred tax assets	$ 59,200,000

Income Taxes - Changes in Valua

Income Taxes - Changes in Valuation Allowance (Details) - Tax Valuation Allowance - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Valuation Allowance [Line Items]
Beginning balance	$ 129,840	$ 77,215	$ 125,462	$ 129,408
Charges	2,269	77,138	790	29,345
Deductions	(2,701)	(24,513)	(67,019)	(33,291)
Ending balance	$ 129,408	$ 129,840	$ 59,233	$ 125,462

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets
Loss and tax credit carryforwards – state	$ 48,172	$ 54,943
Derivative contracts	0	30,892
Accrued liabilities and other reserves	19,155	19,567
Business credit carryforwards	10,487	18,066
Loss carryforwards – federal	0	10,310
Lease liabilities	1,998	4,523
Property and equipment	0	2,613
Other	5,974	4,206
Valuation allowances	(59,233)	(125,462)
Total deferred tax assets	26,553	19,658
Deferred tax liabilities
Property and equipment	(78,055)	0
CO2 and other contracts	(15,304)	(17,208)
Operating lease right-of-use assets	(2,770)	(4,088)
Derivative contracts	(1,544)	0
Total deferred tax liabilities	(97,673)	(21,296)
Total net deferred tax liability	$ (71,120)	$ (1,638)

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Effective Income Tax Rate Reconciliation, Amount
Income tax provision calculated using the federal statutory income tax rate	$ (11,169)	$ (388,228)	$ 116,551	$ 11,921
State income taxes	8,509	(120,340)	20,642	1,468
Tax windfall on stock-based compensation deduction	0	(1,380)	(158)	(267)
Nondeductible compensation	0	0	2,303	5,057
Change in valuation allowance	(432)	52,625	(66,229)	(3,946)
EOR and other	0	0	(1,530)	(14,272)
Tax attributes reduction – net of cancellation of indebtedness income exclusion	0	31,667	0	0
Other	566	9,527	3,265	806
Total income tax expense (benefit)	$ (2,526)	$ (416,129)	$ 74,844	$ 767

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands		2 Months Ended	3 Months Ended	4 Months Ended	9 Months Ended	12 Months Ended
	Jun. 01, 2022	Jul. 31, 2022	Dec. 31, 2020	Dec. 31, 2022	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021	Aug. 02, 2022	May 31, 2022
Defined Contribution Benefit Plans Disclosures [Line Items]
Stock repurchase program								$ 100,000	$ 250,000
Treasury stock, shares, acquired		1,615,356
Treasury stock, value, acquired, cost method		$ 100,000
Treasury stock acquired, average cost per share (in dollars per share)		$ 61.92
Stock repurchase program, remaining authorized repurchase amount				$ 250,000		$ 250,000
Carrying value of shares acquired						$ 0
Employee stock purchase plan (in shares)				7,604
Employee Stock Purchase Plan
Defined Contribution Benefit Plans Disclosures [Line Items]
Discount to fair market value of a share of common stock under employee stock purchase plan (as a percent)	15%
Treasury Stock (at cost)
Defined Contribution Benefit Plans Disclosures [Line Items]
Treasury stock, shares, retired						1,615,391
Carrying value of shares acquired						$ 100,030
Maximum | Employee Stock Purchase Plan
Defined Contribution Benefit Plans Disclosures [Line Items]
Share-based compensation arrangement by share-based payment award, number of shares authorized	2,000,000
Maximum employee contribution rate under employee stock purchase plan (as a percent)	10%
401(k) Plan
Defined Contribution Benefit Plans Disclosures [Line Items]
Employer contribution rate						100%
Employer's matching contributions			$ 1,100		$ 4,400	$ 5,800	$ 5,100
401(k) Plan | Maximum
Defined Contribution Benefit Plans Disclosures [Line Items]
Employee contribution rate						6%

Stock Compensation - Stock-Base

Stock Compensation - Stock-Based Compensation Costs (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Stock-based compensation expense included in G&A	$ 8,212	$ 4,111	$ 16,055	$ 25,322
Stock-based compensation capitalized	695	1,660	1,012	1,883
Total cost of stock-based compensation arrangements	8,907	5,771	17,067	27,205
Income tax benefit recognized for stock-based compensation arrangements	$ 2,053	$ 1,028	$ 1,663	$ 1,846

Stock Compensation - Narrative

Stock Compensation - Narrative (Details)		1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 04, 2020 shares	Mar. 31, 2022	Jun. 30, 2020 USD ($)	Sep. 18, 2020 USD ($) shares	Sep. 18, 2020 USD ($) shares	Dec. 31, 2022 USD ($) shares
Stock Compensation
Total executives and senior managers receiving cash retention incentive			21
Total cash retention incentives paid to executive officers and senior managers			$ 15,200,000
Repayment percentage based on continued employment up to 12 months			50%
Repayment percentage based on achieving incentive metrics			50%
Unrecognized compensation expense			$ 18,700,000
Incremental compensation expense			$ 4,100,000
Acceleration of predecessor stock compensation expense				$ 4,600,000	$ 4,601,000
Maximum
Stock Compensation
Repayment percentage			100%
Restricted Stock Units
Stock Compensation
Total grants (in shares) | shares						15,893
Award vesting or performance period						3 years
Total compensation cost to be recognized in future periods						$ 9,300,000
Weighted average period over which remaining cost will be recognized						10 months 24 days
Restricted Stock Awards
Stock Compensation
Total grants (in shares) | shares						158,692
Total compensation cost to be recognized in future periods						$ 8,700,000
Weighted average period over which remaining cost will be recognized						1 year 7 months 6 days
Performance Share Units
Stock Compensation
Total grants (in shares) | shares						110,385
Award vesting or performance period		3 years				3 years
Share based compensation agreement (as percent)						0.50
Total compensation cost to be recognized in future periods						$ 6,900,000
Weighted average period over which remaining cost will be recognized						2 years 2 months 12 days
Performance Share Units | Tranche One
Stock Compensation
Payout percentage						100%
Performance Share Units | Tranche Two
Stock Compensation
Payout percentage						200%
Restricted Stock
Stock Compensation
Award vesting or performance period					3 years
Total compensation cost to be recognized in future periods				0	$ 0
Performance-based equity awards
Stock Compensation
Award vesting or performance period					3 years 3 months
Total compensation cost to be recognized in future periods				$ 0	$ 0
2020 Omnibus Stock and Incentive Plan
Stock Compensation
Maximum number of common stock shares authorized for issuance under Plan | shares						6,200,000
Total grants (in shares) | shares	2,200,000
Shares available for future awards | shares						3,600,000
2004 Omnibus Stock and Incentive Plan
Stock Compensation
Maximum number of common stock shares authorized for issuance under Plan | shares				61,400,000	61,400,000

Stock Compensation - Vesting Da

Stock Compensation - Vesting Date Fair Value of Restricted Stock Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Units
Stock Compensation
Fair value of restricted stock units vested	$ 0	$ 36,047	$ 31,073
Weighted average fair value of stock awards granted (in dollars per share)	$ 24.67	$ 76.08	$ 31.87
Restricted Stock Awards
Stock Compensation
Fair value of restricted stock units vested	$ 0	$ 6	$ 0
Weighted average fair value of stock awards granted (in dollars per share)	$ 0	$ 76.87	$ 0

Stock Compensation - Restricted

Stock Compensation - Restricted Stock Activity (Details) - $ / shares	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Restricted Stock Units
Number of Awards (in shares)
Nonvested at beginning of period (in shares)		849,907
Granted (in shares)		15,893
Vested (in shares)		(412,065)
Forfeited (in shares)		(23,842)
Nonvested at end of period (in shares)		429,893	849,907
Weighted Average Grant-Date Fair Value (in usd per share)
Weighted average grant-date fair value, Nonvested, beginning of period (in dollars per share)		$ 25.08
Granted (in dollars per share)	$ 24.67	76.08	$ 31.87
Vested (in dollars per share)		25.05
Forfeited (in dollars per share)		24.67
Weighted average grant-date fair value, Nonvested, end of period (in dollars per share)		$ 27.02	$ 25.08
Restricted Stock Awards
Number of Awards (in shares)
Nonvested at beginning of period (in shares)		0
Granted (in shares)		158,692
Vested (in shares)		(98)
Forfeited (in shares)		(5,737)
Nonvested at end of period (in shares)		152,857	0
Weighted Average Grant-Date Fair Value (in usd per share)
Weighted average grant-date fair value, Nonvested, beginning of period (in dollars per share)		$ 0
Granted (in dollars per share)	$ 0	76.87	$ 0
Vested (in dollars per share)		76.08
Forfeited (in dollars per share)		76.08
Weighted average grant-date fair value, Nonvested, end of period (in dollars per share)		$ 76.90	$ 0

Stock Compensation - PSU Award

Stock Compensation - PSU Award Valuation Assumptions (Details) - Performance Share Units - $ / shares	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Stock Compensation
Weighted average fair value of stock awards granted (in dollars per share)	$ 24.19	$ 89.43	$ 0
Expected life (in years)	2 months 23 days	2 years 11 months 15 days
Dividend yield (as percent)	0%	0%
Weighted Average
Stock Compensation
Weighted average risk-free interest rate (as percent)	0.21%	1.76%
Weighted average expected volatility (as percent)	110%	61.60%

Stock Compensation - PSU Activi

Stock Compensation - PSU Activity (Details) - Performance Share Units - $ / shares	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested at beginning of period (in shares)		0
Granted (in shares)		110,385
Vested (in shares)		0
Forfeited (in shares)		(4,273)
Nonvested at end of period (in shares)		106,112	0
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted average grant-date fair value, Nonvested, beginning of period (in dollars per share)		$ 0
Granted (in dollars per share)	$ 24.19	89.43	$ 0
Vested (in dollars per share)		0
Forfeited (in dollars per share)		90.86
Weighted average grant-date fair value, Nonvested, end of period (in dollars per share)		$ 89.37	$ 0

Stock Compensation - Vesting _2

Stock Compensation - Vesting Date and Weighted Average Grant Date Fair Value of PSU Awards (Details) - Performance Share Units - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Stock Compensation
Fair value of performance stock units vested	$ 0	$ 0	$ 45,077
Weighted average fair value of stock awards granted (in dollars per share)	$ 24.19	$ 89.43	$ 0

Stock Compensation - Vesting _3

Stock Compensation - Vesting Date Fair Value of Non-Performance-Based Restricted Stock (Details) $ in Thousands	9 Months Ended
	Sep. 18, 2020 USD ($)
Restricted Stock
Stock Compensation
Fair value of restricted stock units vested	$ 707

Stock Compensation - Performanc

Stock Compensation - Performance-Based TSR Award Assumptions (Details) - Performance-Based TSR Awards	9 Months Ended
	Sep. 18, 2020 $ / shares
Stock Compensation
Weighted average fair value of awards granted (in dollars per share)	$ 0.15
Risk free interest rate	0.27%
Expected life (in years)	3 years
Weighted average expected volatility (as percent)	89.60%
Dividend yield (as percent)	0%

Stock Compensation - Vesting _4

Stock Compensation - Vesting Date Fair Value of Performance-Based Equity Awards (Details) $ in Thousands	9 Months Ended
	Sep. 18, 2020 USD ($)
Performance-Based TSR Awards
Stock Compensation
Fair value of Performance-Based TSR awards vested	$ 79

Commodity Derivative Contract_2

Commodity Derivative Contracts (Details) - NYMEX	Dec. 31, 2022 bbl / d $ / Barrel
Swap | Q1 - Q2 2023
Derivative [Line Items]
Volume per day (in barrels per day) | bbl / d	9,500
Weighted average swap price (in usd per barrel)	76.65
Swap | Q3 - Q4 2023
Derivative [Line Items]
Volume per day (in barrels per day) | bbl / d	11,000
Weighted average swap price (in usd per barrel)	78.48
Collar | Q1 - Q2 2023
Derivative [Line Items]
Volume per day (in barrels per day) | bbl / d	17,500
Weighted average floor price (in usd per barrel)	69.71
Weighted average ceiling price (in usd per barrel)	100.42
Collar | Q3 - Q4 2023
Derivative [Line Items]
Volume per day (in barrels per day) | bbl / d	9,000
Weighted average floor price (in usd per barrel)	68.33
Weighted average ceiling price (in usd per barrel)	100.69

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy of Financial Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Assets [Abstract]
Oil derivative contracts – current	$ 15,517	$ 0	$ 32,635
Oil derivative contracts – long-term	0		501
Total Assets	15,517
Liabilities [Abstract]
Oil derivative contracts – current	(13,018)	(134,509)	(8,613)
Oil derivative contracts – long-term	0	0	$ (295)
Total Liabilities	(13,018)	(134,509)
Quoted Prices in Active Markets (Level 1)
Assets [Abstract]
Oil derivative contracts – current	0
Oil derivative contracts – long-term	0
Total Assets	0
Liabilities [Abstract]
Oil derivative contracts – current	0	0
Oil derivative contracts – long-term	0	0
Total Liabilities	0	0
Significant Other Observable Inputs (Level 2)
Assets [Abstract]
Oil derivative contracts – current	15,517
Oil derivative contracts – long-term	0
Total Assets	15,517
Liabilities [Abstract]
Oil derivative contracts – current	(13,018)	(134,509)
Oil derivative contracts – long-term	0	0
Total Liabilities	(13,018)	(134,509)
Significant Unobservable Inputs (Level 3)
Assets [Abstract]
Oil derivative contracts – current	0
Oil derivative contracts – long-term	0
Total Assets	0
Liabilities [Abstract]
Oil derivative contracts – current	0	0
Oil derivative contracts – long-term	0	0
Total Liabilities	$ 0	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair value of debt	$ 29	$ 35

Commitments and Contingencies (

Commitments and Contingencies (Details) MMcf in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / Barrel MMcf	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)
Long-term Purchase Commitment [Line Items]
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel	75
Estimated litigation liability, current		$ 3,900,000
Material tax assessments	$ 0
Industrial-sourced CO2 purchase contracts
Long-term Purchase Commitment [Line Items]
Term of long-term purchase commitments	6 years
Processing fee related to overriding royalty interest in CO2 | Minimum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2	$ 40,600,000
Processing fee related to overriding royalty interest in CO2 | Maximum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2	$ 52,000,000
Industrial CO2 customer contracts
Long-term Purchase Commitment [Line Items]
Significant supply commitment remaining volume committed (MMcf) | MMcf	478
Term of long-term supply arrangement	12 years
CO2 Storage Agreement
Long-term Purchase Commitment [Line Items]
Due in 2023			$ 2,000,000
Due in 2024			2,000,000
Total payments due			$ 4,000,000

Additional Balance Sheet Deta_3

Additional Balance Sheet Details - Trade and Other Receivables, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade accounts receivable, net	$ 19,619	$ 10,832
Federal income tax receivable, net	597	597
Other receivables	7,127	7,841
Trade and other receivables, net	$ 27,343	$ 19,270	$ 36,221

Additional Balance Sheet Deta_4

Additional Balance Sheet Details - Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020	Sep. 18, 2020	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 22,146	$ 17,137	$ 18,947	$ 23,206
Provision for doubtful accounts	1,060	5,297	1,270	826
Write-offs	0	(288)	0	(5,085)
Ending balance	$ 23,206	$ 22,146	$ 20,217	$ 18,947

Additional Balance Sheet Deta_5

Additional Balance Sheet Details - Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Sep. 18, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts payable	$ 58,905	$ 25,700
Accrued asset retirement obligations – current	36,100	18,373
Accrued lease operating expenses	29,454	27,901
Accrued exploration and development costs	28,963	18,936
Accrued compensation	27,025	23,735
Taxes payable	19,487	14,453
Accrued derivative settlements	9,452	27,336
Other	39,414	35,164
Accounts payable and accrued liabilities	$ 248,800	$ 191,598	$ 174,320

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, 2022	Dec. 31, 2021
Supplemental cash flow information
Cash paid for interest, expensed	$ 813	$ 29,357	$ 1,961	$ 4,227
Cash paid for interest, capitalized	1,261	22,885	4,237	4,585
Cash paid for interest, treated as a reduction of debt	0	46,417	0	0
Cash paid for income taxes	0	453	7,543	184
Cash received from income tax refunds	10,457	1,932	3	3
Noncash investing and financing activities
Increase in asset retirement obligations	23,398	4,328	65,214	112,760
Increase (decrease) in liabilities for capital expenditures	1,867	(12,809)	27,271	35,679
Conversion of convertible senior notes into common stock	$ 0	$ 11,501	$ 0	$ 0