Denbury (DNRWW) 10-K 26 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Jan. 31, 2020	Jun. 30, 2019
Document And Company Information [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-12935
Entity Registrant Name	DENBURY RESOURCES INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-0467835
Entity Address, Address Line One	5320 Legacy Drive,
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	DNR
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
Entity Shell Company	false
Entity Public Float			$ 565,329,480
Entity Common Stock, Shares Outstanding		506,382,897
Entity Central Index Key	0000945764
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019		Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 516		$ 38,560
Accrued production receivable	139,407		125,788
Trade and other receivables, net	18,318		26,970
Derivative assets	11,936		93,080
Other current assets	10,434		11,896
Total current assets	180,611		296,294
Oil and natural gas properties (using full cost accounting)
Proved properties	11,447,680		11,072,209
Unevaluated properties	872,910		996,700
CO2 properties	1,198,846		1,196,795
Pipelines and plants	2,329,078		2,302,817
Other property and equipment	212,334		250,279
Less accumulated depletion, depreciation, amortization and impairment	(11,688,020)		(11,500,190)
Net property and equipment	4,372,828		4,318,610
Operating lease right-of-use assets	34,099		0
Derivative assets	0		4,195
Other assets	104,329		104,123
Total assets	4,691,867		4,723,222
Current liabilities
Accounts payable and accrued liabilities	183,832		198,380
Oil and gas production payable	62,869		61,288
Derivative liabilities	8,346		0
Current maturities of long-term debt (including future interest payable of $86,054 and $85,303, respectively – see Note 6)	102,294	[1]	105,125
Operating lease liabilities	6,901		0
Total current liabilities	364,242		364,793
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $78,860 and $164,914, respectively – see Note 6)	2,232,570		2,664,211
Asset retirement obligations	177,108		174,470
Deferred tax liabilities, net	410,230		309,758
Operating lease liabilities	41,932		0
Other liabilities	53,526		68,213
Total long-term liabilities	2,915,366		3,216,652
Commitments and contingencies (Note 12)
Stockholders' equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	0		0
Common stock, $.001 par value, 750,000,000 shares authorized; 508,065,495 and 462,355,725 shares issued, respectively	508		462
Paid-in capital in excess of par	2,739,099		2,685,211
Accumulated deficit	(1,321,314)		(1,533,112)
Treasury stock, at cost, 1,652,771 and 1,941,749 shares, respectively	(6,034)		(10,784)
Total stockholders' equity	1,412,259		1,141,777
Total liabilities and stockholders' equity	$ 4,691,867		$ 4,723,222
[1]	Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019		Dec. 31, 2018
Stockholders' equity
Preferred stock, par value	$ 0.001		$ 0.001
Preferred stock, shares authorized	25,000,000		25,000,000
Preferred stock, shares issued	0		0
Preferred stock, shares outstanding	0		0
Common stock, par value	$ 0.001		$ 0.001
Common stock, shares authorized	750,000,000
Common stock, shares issued	508,065,495		462,355,725
Treasury stock, shares	1,652,771		1,941,749
Debt Instrument [Line Items]
Future interest payable - current	$ 102,294	[1]	$ 105,125
Future interest payable - long-term	2,232,570		2,664,211
Future interest payable on senior secured notes
Debt Instrument [Line Items]
Future interest payable - current	86,054		85,303
Future interest payable - long-term	$ 78,860		$ 164,914
[1]	Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues and other income	$ 1,274,883	$ 1,473,625	$ 1,129,786
Expenses
Taxes other than income	93,752	104,670	87,207
General and administrative expenses	83,029	71,495	101,806
Interest, net of amounts capitalized of $36,671, $37,079 and $30,762, respectively	81,632	69,688	99,263
Depletion, depreciation, and amortization	233,816	216,449	207,713
Commodity derivatives expense (income)	70,078	(21,087)	77,576
Gain on debt extinguishment	(155,998)	0	0
Other expenses	11,187	84,325	11,455
Total expenses	953,572	1,063,694	1,083,286
Income before income taxes	321,311	409,931	46,500
Income tax provision (benefit)	104,352	87,233	(116,652)
Net income	$ 216,959	$ 322,698	$ 163,152
Net income per common share
Basic	$ 0.47	$ 0.75	$ 0.42
Diluted	$ 0.45	$ 0.71	$ 0.41
Weighted average common shares outstanding
Basic	459,524	432,483	390,928
Diluted	510,341	456,169	395,921
Other income
Revenues and other income	$ 14,523	$ 17,970	$ 10,220
Transportation and marketing
Operating expenses	41,810	43,942	44,064
Oil, natural gas, and related product sales
Revenues and other income	1,212,020	1,422,589	1,089,666
Operating expenses	477,220	489,720	447,799
CO2
Revenues and other income	34,142	31,145	26,182
Operating expenses	2,922	2,816	3,099
Purchased oil sales
Revenues and other income	14,198	1,921	3,718
Operating expenses	$ 14,124	$ 1,676	$ 3,304

Consolidated Statements of Op_2

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Expenses
Capitalized Interest	$ 36,671	$ 37,079	$ 30,762

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities
Net income	$ 216,959	$ 322,698	$ 163,152
Adjustments to reconcile net income to cash flows from operating activities
Depletion, depreciation, and amortization	233,816	216,449	207,713
Deferred income taxes	100,471	103,234	(95,779)
Stock-based compensation	12,470	11,951	15,154
Commodity derivatives expense (income)	70,078	(21,087)	77,576
Receipt (payment) on settlements of commodity derivatives	23,606	(175,248)	(47,795)
Gain on debt extinguishment	(155,998)	0	0
Debt issuance costs and discounts	12,303	6,246	6,191
Other, net	(8,596)	(4,725)	3,112
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(13,619)	20,547	(21,398)
Trade and other receivables	9,379	16,094	(4,421)
Other current and long-term assets	7,629	(6,827)	(1,722)
Accounts payable and accrued liabilities	(3,275)	13,008	(24,710)
Oil and natural gas production payable	2,170	(15,300)	(3,997)
Other liabilities	(13,250)	42,645	(5,933)
Net cash provided by operating activities	494,143	529,685	267,143
Cash flows from investing activities
Oil and natural gas capital expenditures	(262,005)	(316,647)	(262,867)
Acquisitions of oil and natural gas properties	(79)	(541)	(88,886)
CO2 capital expenditures	(3,154)	(5,878)	(2,159)
Pipelines and plants capital expenditures	(27,319)	(23,108)	(2,540)
Net proceeds from sales of oil and natural gas properties and equipment	10,196	7,762	1,696
Other	12,669	5,136	(2,058)
Net cash used in investing activities	(269,692)	(333,276)	(356,814)
Cash flows from financing activities
Bank repayments	(925,791)	(1,982,653)	(1,589,000)
Bank borrowings	925,791	1,507,653	1,763,000
Interest payments treated as a reduction of debt	(85,303)	(79,606)	(50,349)
Proceeds from issuance of senior secured notes	0	450,000	0
Cash paid in conjunction with debt exchange	(136,427)	0	0
Repayment or repurchases of senior subordinated notes	0	0	(2,503)
Costs of debt financing	(11,065)	(16,060)	(6,289)
Pipeline financing and capital lease debt repayments	(13,908)	(23,300)	(27,462)
Other	348	(13,486)	1,216
Net cash provided by (used in) financing activities	(246,355)	(157,452)	88,613
Net increase (decrease) in cash, cash equivalents, and restricted cash	(21,904)	38,957	(1,058)
Cash, cash equivalents, and restricted cash at beginning of year	54,949	15,992	17,050
Cash, cash equivalents, and restricted cash at end of year	$ 33,045	$ 54,949	$ 15,992

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, shares at Dec. 31, 2016		402,334,655			3,906,877
Beginning balance at Dec. 31, 2016	$ 468,448	$ 402	$ 2,534,670	$ (2,018,989)	$ (47,635)
Issued or purchased pursuant to stock compensation plans, shares		5,201,854
Issued or purchased pursuant to stock compensation plans, value		$ 6	(6)
Issued pursuant to directors' compensation plan, shares		12,837
Issued pursuant to notes conversion, value	0
Stock-based compensation, value	19,721		19,721
Tax withholding - stock compensation, shares					1,550,164
Tax withholding - stock compensation, value	(3,183)				$ (3,183)
Retirement of treasury stock, shares		(5,000,000)			(5,000,000)
Retirement of treasury stock, value		$ (5)	(46,557)		$ 46,562
Dividends adjustments, value	27			27
Net income	163,152			163,152
Ending balance, shares at Dec. 31, 2017		402,549,346			457,041
Ending balance at Dec. 31, 2017	648,165	$ 403	2,507,828	(1,855,810)	$ (4,256)
Issued or purchased pursuant to stock compensation plans, shares		4,556,424
Issued or purchased pursuant to stock compensation plans, value		$ 4	(4)
Issued pursuant to notes conversion, shares		55,249,955
Issued pursuant to notes conversion, value	162,004	$ 55	161,949
Stock-based compensation, value	15,438		15,438
Tax withholding - stock compensation, shares					1,484,708
Tax withholding - stock compensation, value	(6,528)				$ (6,528)
Retirement of treasury stock, value					$ 0
Net income	$ 322,698			322,698
Ending balance, shares at Dec. 31, 2018	462,355,725	462,355,725			1,941,749
Ending balance at Dec. 31, 2018	$ 1,141,777	$ 462	2,685,211	(1,533,112)	$ (10,784)
Issued or purchased pursuant to stock compensation plans, shares		9,315,016
Issued or purchased pursuant to stock compensation plans, value		$ 9	(9)
Issued pursuant to directors' compensation plan, shares	97,537
Issued pursuant to senior subordinated notes exchanges, shares		36,297,217			(1,990,000)
Issued pursuant to senior subordinated notes exchanges, value	$ 39,555	$ 37	37,409	(5,161)	$ 7,270
Issued pursuant to notes conversion, value	0
Stock-based compensation, value	16,488		16,488
Tax withholding - stock compensation, shares					1,701,022
Tax withholding - stock compensation, value	(2,520)				$ (2,520)
Retirement of treasury stock, value					$ 0
Net income	$ 216,959			216,959
Ending balance, shares at Dec. 31, 2019	508,065,495	508,065,495			1,652,771
Ending balance at Dec. 31, 2019	$ 1,412,259	$ 508	$ 2,739,099	$ (1,321,314)	$ (6,034)

Nature of Operations and Summar

Nature of Operations and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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 Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations. Principles of Reporting and Consolidation The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“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; and (8) estimates made in the calculation of income taxes. While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. On the Consolidated Statements of Operations for the years ended December 31, 2018 and 2017, “Purchased oil sales” is a new line item and includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from “Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant operating expenses, which were reclassified to “Other expenses,” and also purchases of oil from third parties. Such reclassifications had no impact on our reported total revenues, expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity. Cash, Cash Equivalents, and Restricted Cash We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of year” as reported within the Consolidated Statements of Cash Flows: December 31, In thousands 2019 2018 Cash and cash equivalents $ 516 $ 38,560 Restricted cash included in other assets 32,529 16,389 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 33,045 $ 54,949 Amounts included in restricted cash included in “Other assets” in the accompanying Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations. 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 Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million and $21.4 million during the years ended December 31, 2019 and 2017, respectively, whereby these costs were transferred to the full cost amortization base. We did not record any impairments of our unevaluated costs during the year ended December 31, 2018. Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not record any ceiling test write-downs during 2017, 2018 or 2019. Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables. Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, 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 discovery and operating 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 and Plants 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 . Capitalized costs include $117.6 million of CO 2 pipelines as of December 31, 2019, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2019. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years , and computer equipment and software are generally depreciated over a useful life of three to five years . Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term. Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred. Intangible Assets Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming and are included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO 2 contract intangible asset on a straight-line basis over the contract term. Total amortization expense for our intangible assets was $2.4 million , $2.4 million and $2.4 million during the years ended December 31, 2019 , 2018 and 2017 . The following table summarizes the carrying value of our intangible assets as of December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Intangible asset value $ 37,608 $ 37,848 Accumulated amortization (15,502 ) (13,074 ) Net book value $ 22,106 $ 24,774 As of December 31, 2019 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2020 $ 2,420 2021 2,420 2022 2,420 2023 2,420 2024 2,420 Impairment Assessment of Long-Lived Assets 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 whenever events or changes in circumstances indicate that the carrying value may not be recoverable. 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. 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, 2019. Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and 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, unless significant. 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, 2019 , three purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP ( 32% ), Hunt Crude Oil Supply Company ( 11% ) and Sunoco Inc. ( 11% ). For the year ended December 31, 2018 , two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP ( 24% ) and Hunt Crude Oil Supply Company ( 10% ). For the year ended December 31, 2017, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP ( 22% ) and Marathon Petroleum Company ( 10% ). Other Receivables During 2018, we recorded a $16.9 million impairment of a loan related to a proposed plant in the Gulf Coast that would potentially supply CO 2 to Denbury, due to uncertainties of the project achieving financial close. The impairment was included within “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018. Income Taxes Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Net Income per Common Share Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible. The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating basic and diluted net income per common share for the periods indicated: Year Ended December 31, In thousands 2019 2018 2017 Numerator Net income – basic $ 216,959 $ 322,698 $ 163,152 Effect of potentially dilutive securities Interest expensed on convertible senior notes including amortization of discount, net of tax 14,134 539 49 Net income – diluted $ 231,093 $ 323,237 $ 163,201 Denominator Weighted average common shares outstanding – basic 459,524 432,483 390,928 Effect of potentially dilutive securities Restricted stock and performance-based equity awards 2,396 6,500 2,242 Convertible senior notes (1) 48,421 17,186 2,751 Weighted average common shares outstanding – diluted 510,341 456,169 395,921 (1) For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 6 , Long-Term Debt – 2019 Debt Reduction Transactions ). Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods. In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”) converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion. See Note 6 , Long-Term Debt , for further discussion. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2019 2018 2017 Stock appreciation rights 2,027 2,743 4,512 Restricted stock and performance-based equity awards 5,505 1,234 5,645 Environmental and Litigation Contingencies The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors. Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain. Recent Accounting Pronouncements Recently Adopted Leases. Effective January 1, 2019, we adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”), and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842 , using the modified retrospective method with an application date of January 1, 2019. ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. We elected the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow lease and non-lease components to be combined, and carry forward our accounting treatment for existing land easement agreements. The adoption of the new standards resulted in the recognition of $39.1 million of lease right-of-use assets and $55.8 million of operating lease liabilities ( $16.7 million of which related to previously-existing lease obligations) as of January 1, 2019, in our Consolidated Balance Sheets, but did not materially impact our results of operations and had no impact on our cash flows. The additional lease right-of-use assets and operating lease liabilities recorded on our balance sheet primarily related to our leases for office space, as the accounting for our financing leases and pipeline financings was relatively unchanged. Not Yet Adopted Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. We intend to adopt the standard using a modified retrospective approach with an application date of January 1, 2020. The adoption of ASU 2016-13 is not expected to have a material effect on our consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. We plan to adopt the standard with an application date of January 1, 2020. The adoption of ASU 2018-13 is not expected to have a material effect on our consolidated financial statements but may require enhanced footnote disclosures.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Note 2. Revenue Recognition We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers . The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition: • Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection. • Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of ownership (the identified performance obligation is satisfied). • Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO 2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts. • Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary. • Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO 2 contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets, which was $139.4 million and $125.8 million as of December 31, 2019 and December 31, 2018 , respectively. In addition to revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts, the Company enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Disaggregation of Revenue The following table summarizes our revenues by product type for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, In thousands 2019 2018 2017 Oil sales $ 1,205,083 $ 1,412,358 $ 1,079,703 Natural gas sales 6,937 10,231 9,963 CO 2 sales and transportation fees 34,142 31,145 26,182 Purchased oil sales 14,198 1,921 3,718 Total revenues $ 1,260,360 $ 1,455,655 $ 1,119,566

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Note 3. 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 6 years , with certain land leases having remaining terms up to 50 years . Leases with a term of 12 months or less are not recorded on our balance sheet. During the third quarter of 2019, we exercised the early buyout option on our remaining finance leases. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consists of our office leases: December 31, In thousands 2019 Operating leases Operating lease right-of-use assets $ 34,099 Operating lease liabilities - current $ 6,901 Operating lease liabilities - long-term 41,932 Total operating lease liabilities $ 48,833 The majority of our leases contain renewal options, typically exercisable at our sole discretion. We record right-of-use assets and liabilities based on the present value of lease payments over the initial lease term, unless the option to extend the lease is reasonably certain, and utilize our incremental borrowing rate based on information available at the lease commencement date. The following weighted average remaining lease terms and discount rates related to our outstanding operating leases: December 31, 2019 Weighted average remaining lease term 5.7 years Weighted average discount rate 6.7 % Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. We have subleased part of the office space included in our operating leases. We expect to receive a total of approximately $10.4 million for 2020 through 2025 under our sublease agreements. The following table summarizes the components of lease costs and sublease income: Year Ended In thousands Income Statement December 31, 2019 Operating lease cost General and administrative expenses $ 8,924 Lease operating expenses 58 CO 2 discovery and operating expenses 5 $ 8,987 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ 1,188 Interest on lease liabilities Interest expense 40 Total finance lease cost $ 1,228 Sublease income General and administrative expenses $ 4,127 Our statement of cash flows included the following activity related to our operating and finance leases: Year Ended In thousands December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 10,995 Operating cash flows from interest on finance leases 40 Financing cash flows from finance leases 1,275 Right-of-use assets obtained in exchange for lease obligations Operating leases 415 Finance leases — The following table summarizes by year the maturities of our minimum lease payments as of December 31, 2019 , but excludes future sublease receipts associated with sublease contracts we have for a portion of these operating leases: Operating In thousands Leases 2020 $ 9,934 2021 10,056 2022 10,259 2023 10,300 2024 10,317 Thereafter 8,287 Total minimum lease payments 59,153 Less: Amount representing interest (10,320 ) Present value of minimum lease payments $ 48,833 The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted for under previous accounting guidance under FASC Topic 840, Leases , as of December 31, 2018: Operating In thousands Leases 2019 $ 10,690 2020 9,776 2021 10,007 2022 10,223 2023 10,262 Thereafter 18,169 Total minimum lease payments $ 69,127

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 4. Asset Retirement Obligations The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2019 and 2018 : Year Ended December 31, In thousands 2019 2018 Beginning asset retirement obligations $ 176,585 $ 166,310 Liabilities incurred and assumed during period 4,354 2,201 Revisions in estimated retirement obligations 9,206 2,298 Liabilities settled and sold during period (24,342 ) (9,481 ) Accretion expense 15,957 15,257 Ending asset retirement obligations 181,760 176,585 Less: current asset retirement obligations (1) (4,652 ) (2,115 ) Long-term asset retirement obligations $ 177,108 $ 174,470 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets. Liabilities assumed relate to minor acquisitions, with liabilities incurred generally relating to wells and facilities. We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $53.4 million and $42.1 million as of December 31, 2019 and 2018 , respectively. These balances are primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are included in “Other assets” in our Consolidated Balance Sheets. A portion of these investments are included in cash, cash equivalents, and restricted cash balances on our Consolidated Statements of Cash Flows (see Note 1, Nature of Operations and Summary of Significant Accounting Policies – Cash, Cash Equivalents, and Restricted Cash ). The carrying value of these investments approximates their estimated fair market value as of December 31, 2019 and 2018 .

Unevaluated Property

Unevaluated Property	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Unevaluated Property	Note 5. Unevaluated Property A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2019 , and the year in which the costs were incurred follows: December 31, 2019 Costs Incurred During: In thousands 2019 2018 2017 2016 and Prior Total Property acquisition costs $ — $ — $ 8,527 $ 572,930 $ 581,457 Exploration and development 3,522 1,862 3,175 108,268 116,827 Capitalized interest 31,489 27,013 23,134 92,990 174,626 Total $ 35,011 $ 28,875 $ 34,836 $ 774,188 $ 872,910 Our property acquisition costs for 2016 and prior were primarily related to the fair value allocated to the purchase of interests in the Cedar Creek Anticline (“CCA”) and Hartzog Draw, as well as CO 2 tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2019 . The most significant development costs incurred during each period relate to development in preparation for the CO 2 floods at Webster, Conroe, and CCA fields. We have not yet recognized proved tertiary reserves in these fields. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at lea st annually. We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten years . Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Note 6. Long-Term Debt The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Senior Secured Bank Credit Agreement $ — $ — 9% Senior Secured Second Lien Notes due 2021 614,919 614,919 9¼% Senior Secured Second Lien Notes due 2022 455,668 455,668 7¾% Senior Secured Second Lien Notes due 2024 531,821 — 7½% Senior Secured Second Lien Notes due 2024 20,641 450,000 6⅜% Convertible Senior Notes due 2024 245,548 — 6⅜% Senior Subordinated Notes due 2021 51,304 203,545 5½% Senior Subordinated Notes due 2022 58,426 314,662 4⅝% Senior Subordinated Notes due 2023 135,960 307,978 Pipeline financings 167,439 180,073 Capital lease obligations — 5,362 Total debt principal balance 2,281,726 2,532,207 Debt discount (1) (101,767 ) — Future interest payable (2) 164,914 250,218 Debt issuance costs (10,009 ) (13,089 ) Total debt, net of debt issuance costs and discount 2,334,864 2,769,336 Less: current maturities of long-term debt (3) (102,294 ) (105,125 ) Long-term debt and capital lease obligations $ 2,232,570 $ 2,664,211 (1) Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $27.0 million and $74.8 million , respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019 . (2) Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors . (3) Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months. The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all our outstanding senior secured, convertible senior, and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries. Senior Secured Bank Credit Facility In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (February 12, 2021, May 14, 2021 or August 13, 2021) if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”), respectively, are not repaid or refinanced by each of their respective maturity dates. As of December 31, 2019, the borrowing base and lender commitments for the revolving credit facility were $615 million , and scheduled redeterminations of the borrowing base are to occur semiannually in May and November of each year, with the next such redetermination being scheduled for May 2020. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million , which may be increased at the sole discretion of the administrative agent, 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. The Bank Credit Agreement is guaranteed jointly and severally by each subsidiary of DRI that is 100% owned, directly or indirectly, by DRI and is secured by (1) a significant portion of our proved oil and natural gas properties held through DRI’s restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of commodity derivative agreements of DRI and such subsidiaries (as applicable); and (4) a pledge of deposit accounts, securities accounts and commodity accounts of DRI and such subsidiaries (as applicable). The Bank Credit Agreement limits our ability to, among other things, incur and repay indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make distributions and dividends; and enter into commodity derivative agreements, in each case subject to customary exceptions. The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following: • A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter; • A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio; • A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and • A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 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 borrowing base availability under the senior secured bank credit facility, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. As of December 31, 2019, (1) loans under the Bank Credit Agreement were subject to varying rates of interest based on either (a) for ABR Loans, a base rate determined under the Bank Credit Agreement (the “ABR”) plus an applicable margin ranging from 1.75% to 2.75% per annum, or (b) for LIBOR Loans, the LIBOR rate plus an applicable margin ranging from 2.75% to 3.75% per annum (capitalized terms as defined in the Bank Credit Agreement) and (2) the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement was subject to a commitment fee of 0.50% . As of December 31, 2019, we had no outstanding borrowings, $87.2 million of letters of credit outstanding and were in compliance with all debt covenants under the Bank Credit Agreement. The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC. 2019 Debt Reduction Transactions During the third quarter of 2019, we repurchased $11.0 million in aggregate principal amount of our then outstanding 5½% Senior Subordinated Notes due 2022 (the “2022 Senior Subordinated Notes”) in open market transactions for a total purchase price of $5.3 million , excluding accrued interest. Additionally, during the fourth quarter of 2019, we repurchased principally through exchanges an additional $25.3 million in aggregate principal amount of our then outstanding 2022 Senior Subordinated Notes and $75.7 million in aggregate principal amount of our then outstanding 4⅝% Senior Subordinated Notes due 2023 (the “2023 Senior Subordinated Notes”) for $11.2 million in cash and issuance of 38.3 million shares of the Company’s common stock. In connection with these transactions, we recognized a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2019, in our Consolidated Statements of Operations. During June 2019, in a series of debt exchanges, we extended the maturities of our outstanding long-term debt and reduced the amount of our outstanding debt principal. As part of these transactions, holders exchanged a total of $468.4 million aggregate principal amount of our then outstanding senior subordinated notes for $102.6 million aggregate principal amount of new 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of new 2024 Convertible Senior Notes and $120.0 million of cash. The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of our 2021 Senior Subordinated Notes, $219.9 million aggregate principal amount of our 2022 Senior Subordinated Notes and $96.3 million aggregate principal amount of our 2023 Senior Subordinated Notes. In addition, holders also exchanged $425.4 million of 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes. In July 2019, holders exchanged an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. As a result, we recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.5 million for the year ended December 31, 2019, in our Consolidated Statements of Operations. In accordance with FASC 470-50, Modifications and Extinguishments , the June 2019 exchange of our existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million , respectively. These debt discounts will be amortized as interest expense over the terms of these notes. Separately, the June 2019 exchange of our existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the new 7¾% Senior Secured Notes, which discount will be amortized as interest expense over the term of these notes. January 2018 Senior Subordinated Note Exchanges During January 2018, we closed transactions to exchange a total of $174.3 million aggregate principal amount of our then existing senior subordinated notes for $74.1 million aggregate principal amount of new 2022 Senior Secured Notes and $59.4 million aggregate principal amount of our previously outstanding 2023 Convertible Senior Notes, resulting in a net reduction in our debt principal from these exchanges of $40.8 million . The exchanged notes consisted of $11.6 million aggregate principal amount of our 2021 Senior Subordinated Notes, $94.2 million aggregate principal amount of our 2022 Senior Subordinated Notes and $68.5 million aggregate principal amount of our 2023 Senior Subordinated Notes. In May 2018, the debt principal balance and future interest applicable to the 2023 Convertible Senior Notes were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Consolidated Balance Sheets following the conversion of the notes into shares of Denbury common stock (see Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in April and May 2018 below for further discussion). 2017 Senior Subordinated Note Exchanges During December 2017, we entered into privately negotiated agreements to exchange a total of $609.8 million aggregate principal amount of our existing senior subordinated notes for $381.6 million aggregate principal amount of new 2022 Senior Secured Notes and $84.7 million aggregate principal amount of 3½% Convertible Senior Notes due 2024, resulting in a net reduction in our debt principal from these exchanges of $143.6 million . The exchanged notes consisted of $364.0 million aggregate principal amount of our 2022 Senior Subordinated Notes and $245.8 million aggregate principal amount of our 2023 Senior Subordinated Notes. Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in April and May 2018 During the second quarter of 2018, holders of all $59.4 million aggregate principal amount outstanding of our 2023 Convertible Senior Notes and $84.7 million aggregate principal amount outstanding of our 3½% Convertible Senior Notes due 2024 converted their notes into shares of Denbury common stock, at the rates specified in the indentures for these notes, resulting in the issuance of 55.2 million shares of our common stock upon conversion. The debt principal balances and future interest treated as debt applicable to the 2023 Convertible Senior Notes and 3½% Convertible Senior Notes due 2024, totaling $162.0 million , were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Consolidated Balance Sheets upon the conversion of the notes into shares of Denbury common stock. As of April 18, 2018 and May 30, 2018, there were no remaining 3½% Convertible Senior Notes due 2024 and 2023 Convertible Senior Notes outstanding, respectively. Senior Secured Second Lien Notes 9% Senior Secured Second Lien Notes due 2021. In May 2016, we issued $614.9 million of 2021 Senior Secured Notes. The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of existing senior subordinated notes. The 2021 Senior Secured Notes mature on May 15, 2021, and interest is payable semiannually in arrears on May 15 and November 15 of each year. At any time prior to December 15, 2020, we may redeem the 2021 Senior Secured Notes in whole or in part at our option, at a redemption price of 104.50% of the principal amount, and at par thereafter, as specified in the indenture. The 2021 Senior Secured Notes are not subject to any sinking fund requirements. The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. 9¼% Senior Secured Second Lien Notes due 2022. In December 2017 and January 2018, we issued $381.6 million and $74.1 million , respectively, of 2022 Senior Secured Notes. The 2022 Senior Secured Notes, which bear interest at a rate of 9.25% per annum, were issued at par in connection with exchanges with a limited number of holders of existing senior subordinated notes (see January 2018 Senior Subordinated Note Exchanges and 2017 Senior Subordinated Note Exchanges above). The 2022 Senior Secured Notes mature on March 31, 2022, and interest is payable semiannually in arrears on March 31 and September 30 of each year. We may redeem the 2022 Senior Secured Notes in whole or in part at our option, at a redemption price of 109.25% of the principal amount at any time prior to March 31, 2020, 104.625% of the principal amount prior to March 31, 2021, and at par thereafter. The 2022 Senior Secured Notes are not subject to any sinking fund requirements. The 2022 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. 7¾% Senior Secured Second Lien Notes due 2024. In June 2019, we issued $528.0 million of 7¾% Senior Secured Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes and existing 7½% Senior Secured Notes (see 2019 Debt Reduction Transactions above). The 7¾% Senior Secured Notes, which carry a stated interest rate of 7.75% per annum, were recorded at approximately 94% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments , which equates to an effective yield to maturity of approximately 9.39% . In July 2019, we issued an additional $3.8 million of 7¾% Senior Secured Notes in exchange for $4.0 million of 7½% Senior Secured Notes, which were recorded at par. The 7¾% Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually in arrears on February 15 and August 15 of each year. We may redeem the 7¾% Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.875% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7¾% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7¾% Senior Secured Notes at a price of 107.75% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7¾% Senior Secured Notes are not subject to any sinking fund requirements. The 7¾% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. 7½% Senior Secured Second Lien Notes due 2024. In August 2018, we issued $450.0 million of 7½% Senior Secured Notes. The 7½% Senior Secured Notes, which bear interest at a rate of 7.50% per annum, were issued at par to repay outstanding borrowings on our Bank Credit Agreement, with additional proceeds used for general corporate purposes. After note exchanges completed in June and July of 2019, $20.6 million principal amount of the 7½% Senior Secured Notes remained outstanding as of December 31, 2019. The 7½% Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually in arrears on February 15 and August 15 of each year. We may redeem the 7½% Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.75% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7½% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7½% Senior Secured Notes at a price of 107.50% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 7½% Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7½% Senior Secured Notes are not subject to any sinking fund requirements. The 7½% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. Restrictive Covenants in Indentures for Senior Secured Second Lien Notes. Each of the indentures for the 2021 Senior Secured Notes, 2022 Senior Secured Notes, 7¾% Senior Secured Notes and 7½% Senior Secured Notes contains customary covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a Leverage Ratio (as defined in the indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). As of December 31, 2019, we were in compliance with all debt covenants under the indentures related to our senior secured second lien notes. Convertible Senior Notes 6⅜% Convertible Senior Notes due 2024. In June 2019, we issued $245.5 million of 2024 Convertible Senior Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes (see 2019 Debt Reduction Transactions above). The 2024 Convertible Senior Notes, which carry a stated interest rate of 6.375% per annum, were recorded at approximately 67% of their principal amount in accordance with FASC 470-50, Modifications and Extinguishments , which equates to an effective yield to maturity of approximately 15.31% . Interest on the 2024 Convertible Senior Notes is payable semiannually in arrears on June 30 and December 30 of each year and mature on December 31, 2024. We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity. The 2024 Convertible Senior Notes are convertible into shares of our common stock at any time, at the option of the holders, at a rate of 370 shares of common stock per $1,000 principal amount of 2024 Convertible Senior Notes, which is equivalent to approximately 90.9 million shares of the Company’s common stock, subject to customary adjustments to the conversion rate and threshold price with respect to, among other things, stock dividends and distributions, mergers and reclassifications. The 2024 Convertible Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which is $2.43 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. Additionally, the Company may, based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to certain limitations, increase the conversion rate. Any such conversion rate increase would cause a proportional decrease in the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion into common stock at a lower price. Restrictive Covenants in Indentures for Convertible Senior Notes. The indenture for the 2024 Convertible Senior Notes contains certain covenants that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined in the indenture) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). As of December 31, 2019, we were in compliance with all debt covenants under the indenture related to our convertible senior notes. Senior Subordinated Notes 6⅜% Senior Subordinated Notes due 2021. In February 2011, we issued $400 million of 2021 Senior Subordinated Notes. The 2021 Senior Subordinated Notes, which bear interest at a rate of 6.375% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $51.3 million principal amount of the 2021 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2021 Senior Subordinated Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year. We may redeem the 2021 Senior Subordinated Notes in whole or in part at our option at a redemption price of 100% of the principal amount. 5½% Senior Subordinated Notes due 2022. In April 2014, we issued $1.25 billion of 2022 Senior Subordinated Notes. The 2022 Senior Subordinated Notes, which bear interest at a rate of 5.5% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $58.4 million principal amount of the 2022 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2022 Senior Subordinated Notes mature on May 1, 2022, and interest is payable on May 1 and November 1 of each year. At any time prior to May 1, 2020, we may redeem the 2022 Senior Subordinated Notes in whole or in part at our option, at a redemption price of 101.375% of the principal amount, and at par thereafter, as specified in the indenture. The 2022 Senior Subordinated Notes are not subject to any sinking fund requirements. 4⅝% Senior Subordinated Notes due 2023. In February 2013, we issued $1.2 billion of 2023 Senior Subordinated Notes. The 2023 Senior Subordinated Notes, which bear interest at a rate of 4.625% per annum, were sold at par. After note repurchases in open market transactions and exchange transactions completed over the last four years, $136.0 million principal amount of the 2023 Senior Subordinated Notes remained outstanding as of December 31, 2019. The 2023 Senior Subordinated Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year. At any time prior to January 15, 2021, we may redeem the 2023 Senior Subordinated Notes in whole or in part at our option at a redemption price of 100.771% of the principal amount, and at par thereafter, as specified in the indenture. The 2023 Senior Subordinated Notes are not subject to any sinking fund requirements. Restrictive Covenants in Indentures for Senior Subordinated Notes. Each of the indentures for the 2021 Senior Subordinated Notes, 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes contains certain covenants that are generally consistent and that restrict our ability and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided that the restricted payments covenant in the indentures for the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes permits us in certain circumstances to make unlimited restricted payments so long as we maintain a Leverage Ratio (both as defined in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment), although we will not be able to realize the practical benefit of the restricted payment covenant flexibility in the 2022 Senior Subordinated Notes and 2023 Senior Subordinated Notes Indentures until the 2021 Senior Subordinated Notes have been redeemed or retired. As of December 31, 2019 , we were in compliance with all debt covenants under the indentures related to our senior subordinated notes. Pipeline Financings 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 financing, and the Free State Pipeline included a long-term transportation service agreement. These transactions are both accounted for as financing arrangements under FASC Topic 840, Leases . 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 $14.0 million and $19.1 million at December 31, 2019 and 2018 , respectively. Issuance costs associated with our Bank Credit Agreement are included in “Other assets” in our Consolidated Balance Sheets, and issuance costs associated with our senior secured second lien notes, convertible senior notes, and senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in our Consolidated Balance Sheets. Indebtedness Repayment Schedule At December 31, 2019 , our indebtedness, including our financing lease obligations but excluding future interest payable treated as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors , is payable over the next five years and thereafter as follows (assuming our 2024 Convertible Senior Notes do not convert into shares of our common stock prior to maturity): In thousands 2020 $ 15,323 2021 683,562 2022 532,157 2023 155,293 2024 817,297 Thereafter 78,094 Total indebtedness $ 2,281,726

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 7. Income Taxes Our income tax provision (benefit) is as follows: Year Ended December 31, In thousands 2019 2018 2017 Current income tax expense (benefit) Federal $ 2,645 $ (17,885 ) $ (19,485 ) State 1,236 1,884 (1,388 ) Total current income tax expense (benefit) 3,881 (16,001 ) (20,873 ) Deferred income tax expense (benefit) Federal 89,950 93,395 (113,863 ) State 10,521 9,839 18,084 Total deferred income tax expense (benefit) 100,471 103,234 (95,779 ) Total income tax expense (benefit) $ 104,352 $ 87,233 $ (116,652 ) At December 31, 2019 , we had no federal net operating loss carryforwards (“NOLs”), tax effected business interest expense carryforward totaling $24.5 million (before provision for valuation allowance), state NOLs and tax credits totaling $52.9 million (before provision for valuation allowance), an estimated $49.9 million of enhanced oil recovery credits to carry forward related to our tertiary operations, an estimated $21.6 million of research and development credits, and $6.0 million of alternative minimum tax credits. Under the Tax Cut and Jobs Act (“the Act”) enacted in December 2017, all of our alternative minimum tax credits are fully refundable by 2021 and are recorded as a receivable on the balance sheet. We considered our assessment of the recorded tax benefit associated with the impacts of the Act to be substantially complete as of December 31, 2018 , which is reflected in the table reconciling income tax expense below. Federal and state regulatory guidance of the Act are continuing to be issued and could result in further tax effects but are not expected to be material to our financial statements. In addition, the Tax Cut and Jobs Act revised the rules regarding the deductibility of business interest expense by limiting that deduction to 30% of adjusted taxable income (as defined), with disallowed amounts being carried forward to future taxable years. Based on our evaluation, using information existing as of the balance sheet date, of the near-term ability to utilize the tax benefits associated with our 2019 and 2018 disallowed business interest expense, we have established a valuation allowance of $24.5 million for that portion of our business interest expense that is currently expected to exceed the allowed limitation under the Act. Our business interest expense carryforward does not expire. Our state NOLs expire in various years, starting in 2020, although most do not begin to expire until 2025. Our enhanced oil recovery credits and research and development credits begin to expire in 2025 and 2031, respectively. 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, 2019 and 2018 balance sheet dates. As of December 31, 2019 , we had $52.7 million of deferred tax assets associated with State of Louisiana, Mississippi and Alabama net operating losses and tax credits. A tax valuation allowance was recorded in 2015 to reduce the carrying value of our Louisiana deferred tax assets as the result of a tax law enacted in the State of Louisiana, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards. As of December 31, 2019 , tax valuation allowances totaling $41.3 million were recorded for our State of Louisiana deferred tax assets. Based on losses from falling commodity prices and lower future forecasted income related to our Mississippi deferred tax assets, we concluded it was not more likely than not that the deferred tax assets would be realized. Accordingly, we recorded a valuation allowance against our Mississippi deferred tax assets in 2017. As of December 31, 2019, tax valuation allowances totaling $10.6 million were recorded for our State of Mississippi deferred tax assets. During 2019, we recorded a valuation allowance against our Alabama deferred tax assets totaling $0.8 million . After closing on the sale of our Citronelle Field in 2019, our ability to utilize our Alabama net operating losses will be limited, and we concluded it was not more likely than not that the deferred tax assets would be realized. 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 established for our state net operating losses and business interest expense carryforward for 2019, 2018, and 2017 are detailed below: Year Ended December 31, In thousands 2019 2018 2017 Balance at beginning of year $ 51,093 $ 51,134 $ 36,510 Federal 23,124 — — State 2,998 (41 ) 14,624 Balance at end of year $ 77,215 $ 51,093 $ 51,134 As of December 31, 2019 , we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of December 31, 2019 . Significant components of our deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Deferred tax assets Loss and tax credit carryforwards – state $ 52,917 $ 52,366 Business interest expense carryforward 24,513 9,049 Business credit carryforwards 71,555 79,528 Unrecognized gain and original issue discount on debt exchange 41,556 73,937 Accrued liabilities and other reserves 29,788 25,231 Other 18,725 23,208 Valuation allowances (77,215 ) (51,093 ) Total deferred tax assets 161,839 212,226 Deferred tax liabilities Property and equipment (569,254 ) (492,214 ) Derivative contracts (1,120 ) (23,127 ) Other (1,695 ) (6,643 ) Total deferred tax liabilities (572,069 ) (521,984 ) Total net deferred tax liability $ (410,230 ) $ (309,758 ) 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: Year Ended December 31, In thousands 2019 2018 2017 Income tax provision calculated using the federal statutory income tax rate $ 67,475 $ 86,086 $ 16,275 State income taxes, net of federal income tax benefit 7,435 11,968 2,764 Tax shortfall (windfall) on stock-based compensation deduction 1,912 (1,565 ) 5,567 Valuation allowance 26,122 (42 ) 5,562 Enhanced oil recovery tax credits generated — (10,818 ) (11,307 ) Re-measurement of deferreds related to federal tax rate change — — (132,224 ) Other 1,408 1,604 (3,289 ) Total income tax expense (benefit) $ 104,352 $ 87,233 $ (116,652 ) 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 2016 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, 2019
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Note 8. Stockholders’ Equity 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. During 2019 , 2018 and 2017 , our matching contributions to the 401(k) plan were approximately $6.3 million, $6.2 million and $7.1 million, respectively.

Stock Compensation

Stock Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Stock Compensation	Note 9. Stock Compensation The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of March 28, 2019 (the “2004 Plan”), is an incentive plan that provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock appreciation rights (“SARs”) settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock have been authorized for issuance pursuant to the 2004 Plan. As of December 31, 2019 , 13.6 million shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance-based awards. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors. The 2004 Plan was last approved by our stockholders in May 2019 and will expire in May 2029. 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. Stock-based compensation costs for the years ended December 31, 2019 , 2018 and 2017 , are as follows: Year Ended December 31, In thousands 2019 2018 2017 Stock-based compensation expense included in G&A $ 12,470 $ 11,951 $ 15,154 Stock-based compensation capitalized 4,018 3,487 4,567 Total cost of stock-based compensation arrangements $ 16,488 $ 15,438 $ 19,721 Income tax benefit recognized for stock-based compensation arrangements $ 3,118 $ 2,988 $ 5,759 SARs Prior to January 1, 2016, we granted SARs settled in stock to our employees. The SARs generally become exercisable over a three -year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors. The SARs expire over terms not to exceed 7 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee. The SARs were granted with a strike price equal to the fair market value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant. The following is a summary of our SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2018 2,500,885 $ 10.41 Granted — — Exercised — — Forfeited — — Expired (519,729 ) 15.29 Outstanding at December 31, 2019 1,981,156 9.12 1.5 $ — Exercisable at end of period 1,981,156 $ 9.12 1.5 $ — The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested: Year Ended December 31, In thousands 2019 2018 2017 Intrinsic value of SARs exercised $ — $ — $ — Grant-date fair value of SARs vested — 1,095 1,818 As of December 31, 2018, all SARs vested and there was no remaining compensation cost to be recognized in future periods related to nonvested share-based SAR compensation arrangements. There were no exercises of SARs for the years ended December 31, 2019 , 2018 or 2017 . Restricted Stock We grant 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 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. Beginning in 2014, non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. Non-performance-based restricted stock vests over a three -year vesting period, with the specific terms of vesting determined at the time of grant. As of December 31, 2019 , there was $17.4 million of unrecognized compensation expense related to nonvested non-performance-based restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.0 years . The following is a summary of the total vesting date fair value of non-performance-based restricted stock: Year Ended December 31, In thousands 2019 2018 2017 Fair value of restricted stock vested $ 5,743 $ 23,060 $ 9,325 A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during the year ended December 31, 2019 , is presented below: Number Weighted Nonvested at December 31, 2018 8,990,578 $ 3.40 Granted 9,630,155 1.15 Vested (4,612,265 ) 3.20 Forfeited (1,601,032 ) 2.05 Nonvested at December 31, 2019 12,407,436 1.91 Performance-Based Equity Awards Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s officers. Performance-based awards generally vest over 1.25 to 3.25 years for awards granted in 2017 and over 3.25 years for awards granted in 2018 and 2019. The number of performance-based shares earned (and eligible to vest) during the performance period will depend upon: (1) our level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group (“Performance-Based TSR Awards”). 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). With respect to the performance-based equity awards, any amounts earned above the 100% target levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. If performance is below the designated minimum levels, no performance-based shares will be earned. Performance-Based Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued using a Monte Carlo simulation. As of December 31, 2019 , there was $5.7 million of unrecognized compensation expense related to nonvested performance-based equity awards. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.9 years . The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) are as follows: Year Ended December 31, 2019 2018 2017 Weighted average fair value of Performance-Based TSR Awards granted $ 1.95 $ 2.29 $ 3.42 Risk-free interest rate 2.27 % 2.37 % 1.49 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 77.2 % 102.9 % 94.7 % Dividend yield — % — % — % A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2019 , is as follows: Performance-Based Operational Awards Performance-Based TSR Awards Number Weighted Number Weighted Nonvested at December 31, 2018 857,812 $ 2.43 3,806,116 $ 2.71 Granted (1) 980,772 2.13 2,027,660 1.95 Vested (2) — — (1,357,778 ) 1.78 Forfeited — — — — Nonvested at December 31, 2019 1,838,584 2.27 4,475,998 2.65 (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200% , with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. (2) During 2019 , the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 100% of target for each vested TSR performance-based award, representing 1,357,778 aggregate shares of common stock issued. There were no vestings related to Operational performance-based awards during 2019. The following is a summary of the total vesting date fair value of performance-based equity awards: Year Ended December 31, In thousands 2019 2018 2017 Vesting date fair value of Performance-Based Operational Awards $ — $ 595 $ 1,079 Vesting date fair value of Performance-Based TSR Awards 2,783 542 227

Commodity Derivative Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts	Note 10. Commodity Derivative Contracts We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “ Commodity derivatives expense (income) ” in our Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. 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, 2019 , 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, 2019 , none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2020 Fixed-Price Swaps Jan – Dec NYMEX 2,000 $ 60.00 – 61.00 $ 60.59 $ — $ — $ — Jan – Dec Argus LLS 4,500 60.72 – 64.26 62.29 — — — 2020 Three-Way Collars (2) Jan – June NYMEX 23,000 $ 55.00 – 82.65 $ — $ 48.25 $ 56.95 $ 62.83 Jan – June Argus LLS 10,000 58.00 – 87.10 — 52.85 61.52 68.21 July – Dec NYMEX 21,000 55.00 – 82.65 — 48.26 56.85 62.68 July – Dec Argus LLS 8,000 58.00 – 87.10 — 52.75 61.08 68.39 (1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 11. 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 pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of December 31, 2019 , instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $300 thousand in the fair value of these instruments as of December 31, 2019 . 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, 2019 and 2018 : Fair Value Measurements Using: Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2019 Assets Oil derivative contracts – current $ — $ 8,503 $ 3,433 $ 11,936 Total Assets $ — $ 8,503 $ 3,433 $ 11,936 Liabilities Oil derivative contracts – current $ — $ (6,522 ) $ (1,824 ) $ (8,346 ) Total Liabilities $ — $ (6,522 ) $ (1,824 ) $ (8,346 ) December 31, 2018 Assets Oil derivative contracts – current $ — $ 81,621 $ 11,459 $ 93,080 Oil derivative contracts – long-term — 2,030 2,165 4,195 Total Assets $ — $ 83,651 $ 13,624 $ 97,275 Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “ Commodity derivatives expense (income) ” in the accompanying Consolidated Statements of Operations. Level 3 Fair Value Measurements The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2019 and 2018 : Year Ended December 31, In thousands 2019 2018 Fair value of Level 3 instruments, beginning of year $ 13,624 $ — Fair value adjustments on commodity derivatives (8,205 ) 13,624 Receipt on settlements of commodity derivatives (3,810 ) — Fair value of Level 3 instruments, end of year $ 1,609 $ 13,624 The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date $ (556 ) $ 13,624 We utilize an income approach to value our Level 3 three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts: Fair Value at Valuation Technique Unobservable Input Volatility Range Oil derivative contracts $ 1,609 Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after December 31, 2019 12.6% – 34.5% 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. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of December 31, 2019 and 2018 , excluding pipeline financing and capital lease obligations, was $1,833.1 million and $1,886.1 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, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12. Commitments and Contingencies Commitments We have entered into long-term commitments to purchase CO 2 that are either non-cancelable or cancelable only upon the occurrence of specified future events. The commitments continue for up to 9 years . The price we will pay for CO 2 generally varies depending on the amount of CO 2 delivered and the price of oil. Once all commitments have commenced, our annual commitment under these contracts could range from $14 million to $33 million per year, assuming a $60 per Bbl NYMEX oil price. We are party to long-term contracts that require us to deliver CO 2 to our industrial CO 2 customers at various contracted prices. Based upon the maximum amounts deliverable as stated in the industrial contracts, we estimate that we may be obligated to deliver up to 770 Bcf of CO 2 to these customers over the next 15 years . The maximum volume required in any given year is approximately 257 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO 2 reserves at December 31, 2019 , our current production capabilities and our projected levels of CO 2 usage for our own tertiary flooding program. Litigation We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated. Riley Ridge Helium Supply Contract Claim As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20 -year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are capped at an aggregate of $46.0 million over the term of the contract. As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract. On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017). The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions of the helium supply contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Briefing for the appeal by the Company and APMTG is currently expected to be completed in late May or early June, after which oral arguments will be scheduled and heard prior to the Wyoming Supreme Court entering its judgment on the appeal. The timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to extend over the next nine to twelve months. Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract plus $5.2 million of associated costs (through December 31, 2019), for a total of $51.2 million , which is included in “Other liabilities” in our Consolidated Balance Sheets as of December 31, 2019, and $49.4 million of which was accrued in the fourth quarter of 2018. The Company currently has a $32.8 million letter of credit posted as security in this case as part of the appeal process. 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, 2019
Disclosure Text Block [Abstract]
Additional Balance Sheet Details	Note 13. Additional Balance Sheet Details Trade and Other Receivables, Net December 31, In thousands 2019 2018 Trade accounts receivable, net $ 12,630 $ 11,643 Federal income tax receivable, net 2,987 9,037 Commodity derivative settlement receivables 675 2,390 Other receivables 2,026 3,900 Total $ 18,318 $ 26,970

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 14. Supplemental Cash Flow Information Supplemental Cash Flow Information Year Ended December 31, In thousands 2019 2018 2017 Supplemental cash flow information Cash paid for interest, expensed $ 72,842 $ 50,076 $ 98,261 Cash paid for interest, capitalized 36,671 37,079 30,762 Cash paid for interest, treated as a reduction of debt 85,303 79,606 50,349 Cash paid for income taxes 2,361 492 450 Cash received from income tax refunds 9,820 8,280 13,323 Noncash investing and financing activities Increase in asset retirement obligations 13,560 4,499 9,565 Increase (decrease) in liabilities for capital expenditures (17,740 ) 14,600 3,930 Conversion of convertible senior notes into common stock — 162,004 — Retirement of treasury stock — — 46,562

Nature of Operations and Summ_2

Nature of Operations and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations.
Principles of Reporting and Consolidation	Principles of Reporting and Consolidation The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“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; and (8) estimates made in the calculation of income taxes. While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. On the Consolidated Statements of Operations for the years ended December 31, 2018 and 2017, “Purchased oil sales” is a new line item and includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from “Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant operating expenses, which were reclassified to “Other expenses,” and also purchases of oil from third parties. Such reclassifications had no impact on our reported total revenues, expenses, net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Cash, Cash Equivalents, and Restricted Cash	Cash, Cash Equivalents, and Restricted Cash We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of year” as reported within the Consolidated Statements of Cash Flows: December 31, In thousands 2019 2018 Cash and cash equivalents $ 516 $ 38,560 Restricted cash included in other assets 32,529 16,389 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 33,045 $ 54,949
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 Financial Accounting Standards Board Codification (“FASC”) Fair Value Measurement topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant. Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million and $21.4 million during the years ended December 31, 2019 and 2017, respectively, whereby these costs were transferred to the full cost amortization base. We did not record any impairments of our unevaluated costs during the year ended December 31, 2018. Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not record any ceiling test write-downs during 2017, 2018 or 2019. Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables. Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO 2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO 2 injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO 2 injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.
Property, Plant, and Equipment Policy	CO 2 Properties We own and produce CO 2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO 2 to third parties when it is produced and sold. Expenses related to the production of CO 2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO 2 discovery and operating 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 and Plants 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 . Capitalized costs include $117.6 million of CO 2 pipelines as of December 31, 2019, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2019. Property and Equipment – Other Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years , and computer equipment and software are generally depreciated over a useful life of three to five years . Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term. Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.
Intangible Assets	Intangible Assets Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to a CO 2 purchase contract with ConocoPhillips to offtake CO 2 from the Lost Cabin gas plant in Wyoming and are included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO 2 contract intangible asset on a straight-line basis over the contract term. Total amortization expense for our intangible assets was $2.4 million , $2.4 million and $2.4 million during the years ended December 31, 2019 , 2018 and 2017 . The following table summarizes the carrying value of our intangible assets as of December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Intangible asset value $ 37,608 $ 37,848 Accumulated amortization (15,502 ) (13,074 ) Net book value $ 22,106 $ 24,774 As of December 31, 2019 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2020 $ 2,420 2021 2,420 2022 2,420 2023 2,420 2024 2,420
Impairment Assessment of Long-Lived Assets	Impairment Assessment of Long-Lived Assets 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 whenever events or changes in circumstances indicate that the carrying value may not be recoverable. 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. 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, 2019.
Asset Retirement Obligations	Asset Retirement Obligations In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and 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, unless significant. Asset retirement obligations are estimated at the present value of expected future net cash flows. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.
Commodity Derivative Contracts	Commodity Derivative Contracts We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. Our derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change. We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “ Commodity derivatives expense (income) ” in our Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. 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, 2019 , 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 per Common Share	Net Income per Common Share Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible. The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating basic and diluted net income per common share for the periods indicated: Year Ended December 31, In thousands 2019 2018 2017 Numerator Net income – basic $ 216,959 $ 322,698 $ 163,152 Effect of potentially dilutive securities Interest expensed on convertible senior notes including amortization of discount, net of tax 14,134 539 49 Net income – diluted $ 231,093 $ 323,237 $ 163,201 Denominator Weighted average common shares outstanding – basic 459,524 432,483 390,928 Effect of potentially dilutive securities Restricted stock and performance-based equity awards 2,396 6,500 2,242 Convertible senior notes (1) 48,421 17,186 2,751 Weighted average common shares outstanding – diluted 510,341 456,169 395,921 (1) For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 6 , Long-Term Debt – 2019 Debt Reduction Transactions ). Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the earliest date outstanding during the respective periods. In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”) converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion. See Note 6 , Long-Term Debt , for further discussion. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2019 2018 2017 Stock appreciation rights 2,027 2,743 4,512 Restricted stock and performance-based equity awards 5,505 1,234 5,645
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 Leases. Effective January 1, 2019, we adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”), and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842 , using the modified retrospective method with an application date of January 1, 2019. ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. We elected the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow lease and non-lease components to be combined, and carry forward our accounting treatment for existing land easement agreements. The adoption of the new standards resulted in the recognition of $39.1 million of lease right-of-use assets and $55.8 million of operating lease liabilities ( $16.7 million of which related to previously-existing lease obligations) as of January 1, 2019, in our Consolidated Balance Sheets, but did not materially impact our results of operations and had no impact on our cash flows. The additional lease right-of-use assets and operating lease liabilities recorded on our balance sheet primarily related to our leases for office space, as the accounting for our financing leases and pipeline financings was relatively unchanged. Not Yet Adopted Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. We intend to adopt the standard using a modified retrospective approach with an application date of January 1, 2020. The adoption of ASU 2016-13 is not expected to have a material effect on our consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. We plan to adopt the standard with an application date of January 1, 2020. The adoption of ASU 2018-13 is not expected to have a material effect on our consolidated financial statements but may require enhanced footnote disclosures.
Revenue Recognition	We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers . The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition: • Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection. • Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of ownership (the identified performance obligation is satisfied). • Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO 2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts. • Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary. • Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO 2 contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Consolidated Balance Sheets, which was $139.4 million and $125.8 million as of December 31, 2019 and December 31, 2018 , respectively. In addition to revenues from oil and natural gas sales contracts and CO 2 sales and transportation contracts, the Company enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.
Leases	We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 6 years , with certain land leases having remaining terms up to 50 years
Stock Compensation	Performance-Based Equity Awards Annually, the Compensation Committee of the Board of Directors grants performance-based equity awards to Denbury’s officers. Performance-based awards generally vest over 1.25 to 3.25 years for awards granted in 2017 and over 3.25 years for awards granted in 2018 and 2019. The number of performance-based shares earned (and eligible to vest) during the performance period will depend upon: (1) our level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of our stock relative to that of a designated peer group (“Performance-Based TSR Awards”). 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). With respect to the performance-based equity awards, any amounts earned above the 100% target levels will be payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. If performance is below the designated minimum levels, no performance-based shares will be earned. Performance-Based Operational Awards are valued using the fair market value of Denbury stock, and Performance-Based TSR Awards are valued using a Monte Carlo simulation. Restricted Stock We grant 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 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. Beginning in 2014, non-performance-based restricted stock awards provide the holders with forfeitable dividend equivalent rights which vests with the underlying shares. Non-performance-based restricted stock vests over a three -year vesting period, with the specific terms of vesting determined at the time of grant. SARs Prior to January 1, 2016, we granted SARs settled in stock to our employees. The SARs generally become exercisable over a three -year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors. The SARs expire over terms not to exceed 7 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee. The SARs were granted with a strike price equal to the fair market value at the time of grant, which is generally defined as the closing price on the NYSE on the date of grant.
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 pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of December 31, 2019 , instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $300 thousand in the fair value of these instruments as of December 31, 2019 . 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, 2019
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 year” as reported within the Consolidated Statements of Cash Flows: December 31, In thousands 2019 2018 Cash and cash equivalents $ 516 $ 38,560 Restricted cash included in other assets 32,529 16,389 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 33,045 $ 54,949 Amounts included in restricted cash included in “Other assets” in the accompanying Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations.
Schedule of Finite-Lived Intangible Assets	The following table summarizes the carrying value of our intangible assets as of December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Intangible asset value $ 37,608 $ 37,848 Accumulated amortization (15,502 ) (13,074 ) Net book value $ 22,106 $ 24,774
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	As of December 31, 2019 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2020 $ 2,420 2021 2,420 2022 2,420 2023 2,420 2024 2,420
Schedule of Earnings Per Share, Basic and Diluted Reconciliation	The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating basic and diluted net income per common share for the periods indicated: Year Ended December 31, In thousands 2019 2018 2017 Numerator Net income – basic $ 216,959 $ 322,698 $ 163,152 Effect of potentially dilutive securities Interest expensed on convertible senior notes including amortization of discount, net of tax 14,134 539 49 Net income – diluted $ 231,093 $ 323,237 $ 163,201 Denominator Weighted average common shares outstanding – basic 459,524 432,483 390,928 Effect of potentially dilutive securities Restricted stock and performance-based equity awards 2,396 6,500 2,242 Convertible senior notes (1) 48,421 17,186 2,751 Weighted average common shares outstanding – diluted 510,341 456,169 395,921 (1) For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 6 , Long-Term Debt – 2019 Debt Reduction Transactions ).
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share, as their effect would have been antidilutive: Year Ended December 31, In thousands 2019 2018 2017 Stock appreciation rights 2,027 2,743 4,512 Restricted stock and performance-based equity awards 5,505 1,234 5,645

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table summarizes our revenues by product type for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, In thousands 2019 2018 2017 Oil sales $ 1,205,083 $ 1,412,358 $ 1,079,703 Natural gas sales 6,937 10,231 9,963 CO 2 sales and transportation fees 34,142 31,145 26,182 Purchased oil sales 14,198 1,921 3,718 Total revenues $ 1,260,360 $ 1,455,655 $ 1,119,566

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
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 consists of our office leases: December 31, In thousands 2019 Operating leases Operating lease right-of-use assets $ 34,099 Operating lease liabilities - current $ 6,901 Operating lease liabilities - long-term 41,932 Total operating lease liabilities $ 48,833
Schedule of Weighted Average Lease Terms and Discount Rates	The following weighted average remaining lease terms and discount rates related to our outstanding operating leases: December 31, 2019 Weighted average remaining lease term 5.7 years Weighted average discount rate 6.7 %
Schedule of Lease Costs	The following table summarizes the components of lease costs and sublease income: Year Ended In thousands Income Statement December 31, 2019 Operating lease cost General and administrative expenses $ 8,924 Lease operating expenses 58 CO 2 discovery and operating expenses 5 $ 8,987 Finance lease cost Amortization of right-of-use assets Depletion, depreciation, and amortization $ 1,188 Interest on lease liabilities Interest expense 40 Total finance lease cost $ 1,228 Sublease income General and administrative expenses $ 4,127
Supplemental Cash Flow Information Related to Leases	Our statement of cash flows included the following activity related to our operating and finance leases: Year Ended In thousands December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 10,995 Operating cash flows from interest on finance leases 40 Financing cash flows from finance leases 1,275 Right-of-use assets obtained in exchange for lease obligations Operating leases 415 Finance leases —
Schedule of Maturities of Operating Lease Liabilities	The following table summarizes by year the maturities of our minimum lease payments as of December 31, 2019 , but excludes future sublease receipts associated with sublease contracts we have for a portion of these operating leases: Operating In thousands Leases 2020 $ 9,934 2021 10,056 2022 10,259 2023 10,300 2024 10,317 Thereafter 8,287 Total minimum lease payments 59,153 Less: Amount representing interest (10,320 ) Present value of minimum lease payments $ 48,833
Schedule of Future Minimum Operating Lease Payments (Topic 840)	The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted for under previous accounting guidance under FASC Topic 840, Leases , as of December 31, 2018: Operating In thousands Leases 2019 $ 10,690 2020 9,776 2021 10,007 2022 10,223 2023 10,262 Thereafter 18,169 Total minimum lease payments $ 69,127

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Changes In Asset Retirement Obligations	The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2019 and 2018 : Year Ended December 31, In thousands 2019 2018 Beginning asset retirement obligations $ 176,585 $ 166,310 Liabilities incurred and assumed during period 4,354 2,201 Revisions in estimated retirement obligations 9,206 2,298 Liabilities settled and sold during period (24,342 ) (9,481 ) Accretion expense 15,957 15,257 Ending asset retirement obligations 181,760 176,585 Less: current asset retirement obligations (1) (4,652 ) (2,115 ) Long-term asset retirement obligations $ 177,108 $ 174,470 (1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Unevaluated Property (Tables)

Unevaluated Property (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Summary of unevaluated properties excluded from oil and natural gas properties being amortized	A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2019 , and the year in which the costs were incurred follows: December 31, 2019 Costs Incurred During: In thousands 2019 2018 2017 2016 and Prior Total Property acquisition costs $ — $ — $ 8,527 $ 572,930 $ 581,457 Exploration and development 3,522 1,862 3,175 108,268 116,827 Capitalized interest 31,489 27,013 23,134 92,990 174,626 Total $ 35,011 $ 28,875 $ 34,836 $ 774,188 $ 872,910

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Components of long-term debt	The table below reflects long-term debt and capital lease obligations outstanding as of December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Senior Secured Bank Credit Agreement $ — $ — 9% Senior Secured Second Lien Notes due 2021 614,919 614,919 9¼% Senior Secured Second Lien Notes due 2022 455,668 455,668 7¾% Senior Secured Second Lien Notes due 2024 531,821 — 7½% Senior Secured Second Lien Notes due 2024 20,641 450,000 6⅜% Convertible Senior Notes due 2024 245,548 — 6⅜% Senior Subordinated Notes due 2021 51,304 203,545 5½% Senior Subordinated Notes due 2022 58,426 314,662 4⅝% Senior Subordinated Notes due 2023 135,960 307,978 Pipeline financings 167,439 180,073 Capital lease obligations — 5,362 Total debt principal balance 2,281,726 2,532,207 Debt discount (1) (101,767 ) — Future interest payable (2) 164,914 250,218 Debt issuance costs (10,009 ) (13,089 ) Total debt, net of debt issuance costs and discount 2,334,864 2,769,336 Less: current maturities of long-term debt (3) (102,294 ) (105,125 ) Long-term debt and capital lease obligations $ 2,232,570 $ 2,664,211 (1) Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $27.0 million and $74.8 million , respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019 . (2) Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors . (3) Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.
Indebtedness repayable over the next five years and thereafter	At December 31, 2019 , our indebtedness, including our financing lease obligations but excluding future interest payable treated as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors , is payable over the next five years and thereafter as follows (assuming our 2024 Convertible Senior Notes do not convert into shares of our common stock prior to maturity): In thousands 2020 $ 15,323 2021 683,562 2022 532,157 2023 155,293 2024 817,297 Thereafter 78,094 Total indebtedness $ 2,281,726

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Tax Provision (Benefit)	Our income tax provision (benefit) is as follows: Year Ended December 31, In thousands 2019 2018 2017 Current income tax expense (benefit) Federal $ 2,645 $ (17,885 ) $ (19,485 ) State 1,236 1,884 (1,388 ) Total current income tax expense (benefit) 3,881 (16,001 ) (20,873 ) Deferred income tax expense (benefit) Federal 89,950 93,395 (113,863 ) State 10,521 9,839 18,084 Total deferred income tax expense (benefit) 100,471 103,234 (95,779 ) Total income tax expense (benefit) $ 104,352 $ 87,233 $ (116,652 )
Valuation Allowance Rollforward	The changes in our valuation allowance established for our state net operating losses and business interest expense carryforward for 2019, 2018, and 2017 are detailed below: Year Ended December 31, In thousands 2019 2018 2017 Balance at beginning of year $ 51,093 $ 51,134 $ 36,510 Federal 23,124 — — State 2,998 (41 ) 14,624 Balance at end of year $ 77,215 $ 51,093 $ 51,134
Deferred Tax Assets And Liabilities	Significant components of our deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Deferred tax assets Loss and tax credit carryforwards – state $ 52,917 $ 52,366 Business interest expense carryforward 24,513 9,049 Business credit carryforwards 71,555 79,528 Unrecognized gain and original issue discount on debt exchange 41,556 73,937 Accrued liabilities and other reserves 29,788 25,231 Other 18,725 23,208 Valuation allowances (77,215 ) (51,093 ) Total deferred tax assets 161,839 212,226 Deferred tax liabilities Property and equipment (569,254 ) (492,214 ) Derivative contracts (1,120 ) (23,127 ) Other (1,695 ) (6,643 ) Total deferred tax liabilities (572,069 ) (521,984 ) Total net deferred tax liability $ (410,230 ) $ (309,758 )
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: Year Ended December 31, In thousands 2019 2018 2017 Income tax provision calculated using the federal statutory income tax rate $ 67,475 $ 86,086 $ 16,275 State income taxes, net of federal income tax benefit 7,435 11,968 2,764 Tax shortfall (windfall) on stock-based compensation deduction 1,912 (1,565 ) 5,567 Valuation allowance 26,122 (42 ) 5,562 Enhanced oil recovery tax credits generated — (10,818 ) (11,307 ) Re-measurement of deferreds related to federal tax rate change — — (132,224 ) Other 1,408 1,604 (3,289 ) Total income tax expense (benefit) $ 104,352 $ 87,233 $ (116,652 )

Stock Compensation (Tables)

Stock Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Stock Compensation
Schedule of stock-based compensation costs	Stock-based compensation costs for the years ended December 31, 2019 , 2018 and 2017 , are as follows: Year Ended December 31, In thousands 2019 2018 2017 Stock-based compensation expense included in G&A $ 12,470 $ 11,951 $ 15,154 Stock-based compensation capitalized 4,018 3,487 4,567 Total cost of stock-based compensation arrangements $ 16,488 $ 15,438 $ 19,721 Income tax benefit recognized for stock-based compensation arrangements $ 3,118 $ 2,988 $ 5,759
Summary of SARs activity	The following is a summary of our SAR activity: Number Weighted Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Outstanding at December 31, 2018 2,500,885 $ 10.41 Granted — — Exercised — — Forfeited — — Expired (519,729 ) 15.29 Outstanding at December 31, 2019 1,981,156 9.12 1.5 $ — Exercisable at end of period 1,981,156 $ 9.12 1.5 $ —
Disclosure of intrinsic value of SARs exercised and grant-date fair value of awards vested	The following is a summary of the total intrinsic value of SARs exercised and grant-date fair value of SARs vested: Year Ended December 31, In thousands 2019 2018 2017 Intrinsic value of SARs exercised $ — $ — $ — Grant-date fair value of SARs vested — 1,095 1,818
Restricted Stock
Stock Compensation
Summary of the total vesting date fair value of non-performance-based restricted stock and performance-based equity awards	The following is a summary of the total vesting date fair value of non-performance-based restricted stock: Year Ended December 31, In thousands 2019 2018 2017 Fair value of restricted stock vested $ 5,743 $ 23,060 $ 9,325
Summary of non-performance-based restricted stock activity	A summary of the status of our nonvested non-performance-based restricted stock grants issued, and the changes during the year ended December 31, 2019 , is presented below: Number Weighted Nonvested at December 31, 2018 8,990,578 $ 3.40 Granted 9,630,155 1.15 Vested (4,612,265 ) 3.20 Forfeited (1,601,032 ) 2.05 Nonvested at December 31, 2019 12,407,436 1.91
Performance-based equity awards
Stock Compensation
Summary of the total vesting date fair value of non-performance-based restricted stock and performance-based equity awards	The following is a summary of the total vesting date fair value of performance-based equity awards: Year Ended December 31, In thousands 2019 2018 2017 Vesting date fair value of Performance-Based Operational Awards $ — $ 595 $ 1,079 Vesting date fair value of Performance-Based TSR Awards 2,783 542 227
Schedule of nonvested performance-based awards activity	A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2019 , is as follows: Performance-Based Operational Awards Performance-Based TSR Awards Number Weighted Number Weighted Nonvested at December 31, 2018 857,812 $ 2.43 3,806,116 $ 2.71 Granted (1) 980,772 2.13 2,027,660 1.95 Vested (2) — — (1,357,778 ) 1.78 Forfeited — — — — Nonvested at December 31, 2019 1,838,584 2.27 4,475,998 2.65 (1) Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200% , with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan. (2) During 2019 , the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 100% of target for each vested TSR performance-based award, representing 1,357,778 aggregate shares of common stock issued. There were no vestings related to Operational performance-based awards during 2019.
Performance-Based TSR Awards
Stock Compensation
Summary of Performance-Based TSR 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) are as follows: Year Ended December 31, 2019 2018 2017 Weighted average fair value of Performance-Based TSR Awards granted $ 1.95 $ 2.29 $ 3.42 Risk-free interest rate 2.27 % 2.37 % 1.49 % Expected life 3.0 years 3.0 years 3.0 years Expected volatility 77.2 % 102.9 % 94.7 % Dividend yield — % — % — %

Commodity Derivative Contracts

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative contracts not classified as hedging instruments	The following table summarizes our commodity derivative contracts as of December 31, 2019 , none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl) Range (1) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2020 Fixed-Price Swaps Jan – Dec NYMEX 2,000 $ 60.00 – 61.00 $ 60.59 $ — $ — $ — Jan – Dec Argus LLS 4,500 60.72 – 64.26 62.29 — — — 2020 Three-Way Collars (2) Jan – June NYMEX 23,000 $ 55.00 – 82.65 $ — $ 48.25 $ 56.95 $ 62.83 Jan – June Argus LLS 10,000 58.00 – 87.10 — 52.85 61.52 68.21 July – Dec NYMEX 21,000 55.00 – 82.65 — 48.26 56.85 62.68 July – Dec Argus LLS 8,000 58.00 – 87.10 — 52.75 61.08 68.39 (1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair value hierarchy of financial assets and liabilities	The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 : Fair Value Measurements Using: Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs In thousands (Level 1) (Level 2) (Level 3) Total December 31, 2019 Assets Oil derivative contracts – current $ — $ 8,503 $ 3,433 $ 11,936 Total Assets $ — $ 8,503 $ 3,433 $ 11,936 Liabilities Oil derivative contracts – current $ — $ (6,522 ) $ (1,824 ) $ (8,346 ) Total Liabilities $ — $ (6,522 ) $ (1,824 ) $ (8,346 ) December 31, 2018 Assets Oil derivative contracts – current $ — $ 81,621 $ 11,459 $ 93,080 Oil derivative contracts – long-term — 2,030 2,165 4,195 Total Assets $ — $ 83,651 $ 13,624 $ 97,275
Changes in fair value of Level 3 assets and liabilities	The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2019 and 2018 : Year Ended December 31, In thousands 2019 2018 Fair value of Level 3 instruments, beginning of year $ 13,624 $ — Fair value adjustments on commodity derivatives (8,205 ) 13,624 Receipt on settlements of commodity derivatives (3,810 ) — Fair value of Level 3 instruments, end of year $ 1,609 $ 13,624 The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date $ (556 ) $ 13,624
Fair Value Measurement Inputs and Valuation Techniques	The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts: Fair Value at Valuation Technique Unobservable Input Volatility Range Oil derivative contracts $ 1,609 Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after December 31, 2019 12.6% – 34.5%

Additional Balance Sheet Deta_2

Additional Balance Sheet Details (Tables)	12 Months Ended
	Dec. 31, 2019
Text Block [Abstract]
Trade and Other Receivables, Net	Trade and Other Receivables, Net December 31, In thousands 2019 2018 Trade accounts receivable, net $ 12,630 $ 11,643 Federal income tax receivable, net 2,987 9,037 Commodity derivative settlement receivables 675 2,390 Other receivables 2,026 3,900 Total $ 18,318 $ 26,970

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, In thousands 2019 2018 2017 Supplemental cash flow information Cash paid for interest, expensed $ 72,842 $ 50,076 $ 98,261 Cash paid for interest, capitalized 36,671 37,079 30,762 Cash paid for interest, treated as a reduction of debt 85,303 79,606 50,349 Cash paid for income taxes 2,361 492 450 Cash received from income tax refunds 9,820 8,280 13,323 Noncash investing and financing activities Increase in asset retirement obligations 13,560 4,499 9,565 Increase (decrease) in liabilities for capital expenditures (17,740 ) 14,600 3,930 Conversion of convertible senior notes into common stock — 162,004 — Retirement of treasury stock — — 46,562

Nature of Ops and Sign. Acctg P

Nature of Ops and Sign. Acctg Policies (Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 516	$ 38,560
Restricted cash included in other assets	32,529	16,389
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 33,045	$ 54,949	$ 15,992	$ 17,050

Nature of Ops and Sign. Acctg_2

Nature of Ops and Sign. Acctg Policies (Intangibles) (Details 1) - CO2 Purchase Contract - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Intangible asset value	$ 37,608	$ 37,848
Accumulated amortization	(15,502)	(13,074)
Net book value	$ 22,106	$ 24,774

Nature of Ops and Sign. Acctg_3

Nature of Ops and Sign. Acctg Policies (Estimated Amortization Expense for Intangibles) (Details 2) $ in Thousands	Dec. 31, 2019USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2020	$ 2,420
2021	2,420
2022	2,420
2023	2,420
2024	$ 2,420

Nature of Ops and Sign. Acctg_4

Nature of Ops and Sign. Acctg Policies (Reconciliation of Weighted Average Shares Table) (Details 3) - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator
Net income - basic		$ 216,959	$ 322,698	$ 163,152
Interest expensed on convertible senior notes including amortization of discount, net of tax		14,134	539	49
Net income - diluted		$ 231,093	$ 323,237	$ 163,201
Denominator
Weighted average common shares outstanding – basic		459,524	432,483	390,928
Restricted stock and performance-based equity awards		2,396	6,500	2,242
Convertible senior notes	[1]	48,421	17,186	2,751
Weighted average common shares outstanding – diluted		510,341	456,169	395,921
Convertible debt instrument, number of equity instruments		90,900
[1]	For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019 (see Note 6 , Long-Term Debt – 2019 Debt Reduction Transactions ).

Significant Accounting Policies

Significant Accounting Policies Nature of Ops and Sign. Acctg Policies (Antidilutive Securities) (Details 4) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock appreciation rights
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,027	2,743	4,512
Restricted stock and performance-based equity awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5,505	1,234	5,645

Significant Accounting Polici_2

Significant Accounting Policies Nature of Ops and Sign. Acctg Policies (Details Textuals) - USD ($) shares in Millions	1 Months Ended	12 Months Ended
	Apr. 17, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Property, Plant and Equipment [Line Items]
Impairments of unevaluated costs		$ 18,200,000	$ 0	$ 21,400,000
Ceiling test write-downs of oil and gas properties		0	0	0
Costs related to CO2 pipelines not placed into service		117,600,000
Amortization of intangible assets		2,400,000	2,400,000	$ 2,400,000
Impairment of long-lived assets		0
Issued pursuant to notes conversion, shares	55.2
Operating lease liabilities		$ 48,833,000			$ 55,800,000
Allowance for loan receivable			$ 16,900,000
Pipelines | Minimum
Property, Plant and Equipment [Line Items]
Useful life		20 years
Pipelines | Maximum
Property, Plant and Equipment [Line Items]
Useful life		50 years
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Useful life		5 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Useful life		10 years
Furniture and Fixtures | Minimum
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 Ops and Sign. Acctg_5

Nature of Ops and Sign. Acctg Policies (Major Customers) (Details Textuals 1)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Plains Marketing LP
Product Information [Line Items]
Revenue from major customer (percentage)	32.00%	24.00%	22.00%
Hunt Crude Oil Company
Product Information [Line Items]
Revenue from major customer (percentage)	11.00%	10.00%
Sunoco Inc
Product Information [Line Items]
Revenue from major customer (percentage)	11.00%
Marathon Petroleum Company
Product Information [Line Items]
Revenue from major customer (percentage)			10.00%

Significant Accounting Polici_3

Significant Accounting Policies Nature of Ops and Sign. Acctg Policies (Effect of the Adoption of ASC Topic 842 Leases) (Details Textuals 2) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating lease liabilities	$ 48,833	$ 55,800
Operating lease right-of-use assets	$ 34,099	39,100	$ 0
Pre-existing lease obligations
Operating lease liabilities		$ 16,700

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue
Revenues	$ 1,260,360	$ 1,455,655	$ 1,119,566
Oil sales
Disaggregation of Revenue
Revenues	1,205,083	1,412,358	1,079,703
Natural gas sales
Disaggregation of Revenue
Revenues	6,937	10,231	9,963
CO2 sales and transportation fees
Disaggregation of Revenue
Revenues	34,142	31,145	26,182
Purchased oil sales
Disaggregation of Revenue
Revenues	$ 14,198	$ 1,921	$ 3,718

Revenue Recognition (Details Te

Revenue Recognition (Details Textuals) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Accrued production receivable	$ 139,407	$ 125,788

Leases (Supplemental Balance Sh

Leases (Supplemental Balance Sheet Information Related to Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Leases, Operating [Abstract]
Operating lease right-of-use assets	$ 34,099	$ 39,100	$ 0
Operating lease liabilities - current	6,901		0
Operating lease liabilities - long-term	41,932		$ 0
Total operating lease liabilities	$ 48,833	$ 55,800

Leases (Lease Term and Discount

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

Leases (Lease Operating Costs)

Leases (Lease Operating Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lease Cost [Line Items]
Operating lease cost	$ 8,987
Lease cost
Amortization of right-of-use assets	1,188
Interest on lease liabilities	40
Total finance lease cost	1,228
Sublease income	4,127
General and administrative expenses
Lease Cost [Line Items]
Operating lease cost	8,924
Lease operating expenses
Lease Cost [Line Items]
Operating lease cost	58
CO2 discovery and operating expenses
Lease Cost [Line Items]
Operating lease cost	$ 5

Leases (Supplemental Cash Flow

Leases (Supplemental Cash Flow Information Related to Leases) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 10,995
Operating cash flows from interest on finance leases	40
Financing cash flows from finance leases	1,275
Right-of-use assets obtained In exchange for lease obligations
Operating leases	415
Finance leases	$ 0

Leases (Maturities of Lease Lia

Leases (Maturities of Lease Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Leases [Abstract]
2020	$ 9,934
2021	10,056
2022	10,259
2023	10,300
2024	10,317
Thereafter	8,287
Total minimum lease payments	59,153
Less: Amount representing interest	(10,320)
Present value of minimum lease payments	$ 48,833	$ 55,800

Leases (Prior Year-End Schedule

Leases (Prior Year-End Schedule of Future Operating Lease Payments) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
2019	$ 10,690
2020	9,776
2021	10,007
2022	10,223
2023	10,262
Thereafter	18,169
Total minimum lease payments	$ 69,127

Leases (Details Textuals)

Leases (Details Textuals) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Future sublease payments to be received	$ 10.4
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	6 years
Land | Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	50 years

Asset Retirement Obligations (R

Asset Retirement Obligations (Rollforward) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Roll Forward [Roll Forward]
Beginning asset retirement obligations		$ 176,585	$ 166,310
Liabilities incurred and assumed during period		4,354	2,201
Revisions in estimated retirement obligations		9,206	2,298
Liabilities settled and sold during period		(24,342)	(9,481)
Accretion expense		15,957	15,257
Ending asset retirement obligations		181,760	176,585
Less: current asset retirement obligations	[1]	(4,652)	(2,115)
Long-term asset retirement obligations		$ 177,108	$ 174,470
[1]	Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details Textuals) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Balance in escrow accounts	$ 53.4	$ 42.1

Unevaluated Property (Summary o

Unevaluated Property (Summary of Unevaluated Properties Excluded from Amortization) (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of unevaluated properties excluded from oil and natural gas properties being amortized
Property acquisition costs	$ 0	$ 0	$ 8,527	$ 572,930
Exploration and development	3,522	1,862	3,175	108,268
Capitalized interest	31,489	27,013	23,134	92,990
Total	35,011	28,875	$ 34,836	$ 774,188
Property acquisition costs	581,457
Exploration and development	116,827
Capitalized interest	174,626
Total	$ 872,910	$ 996,700

Unevaluated Property (Details T

Unevaluated Property (Details Textuals)	12 Months Ended
	Dec. 31, 2019
Minimum
Capitalized Costs of Unproved Properties Excluded from Amortization
Anticipated Timing of Inclusion of Costs in Amortization Calculation	5 years
Maximum
Capitalized Costs of Unproved Properties Excluded from Amortization
Anticipated Timing of Inclusion of Costs in Amortization Calculation	10 years

Long-Term Debt (Components of L

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($)		Dec. 31, 2019		Jun. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Senior Secured Bank Credit Agreement		$ 0			$ 0
Pipeline financings		167,439,000			180,073,000
Capital lease obligations		0			5,362,000
Total debt principal balance		2,281,726,000			2,532,207,000
Debt discount		(101,767,000)	[1]		0
Future interest payable	[2]	164,914,000			250,218,000
Debt issuance costs		(10,009,000)			(13,089,000)
Total debt, net of debt issuance costs and discount		2,334,864,000			2,769,336,000
Less: current maturities of long-term debt		(102,294,000)	[3]		(105,125,000)
Long-term Debt and Lease Obligation		2,232,570,000			2,664,211,000
9% Senior Secured Second Lien Notes due 2021
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 614,919,000			614,919,000
Stated interest rate percentage		9.00%
9 1/4% Senior Secured Second Lien Notes due 2022
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 455,668,000			455,668,000
Stated interest rate percentage		9.25%
7 3/4% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 531,821,000			0
Debt discount		$ (27,000,000)		$ (22,600,000)
Stated interest rate percentage		7.75%
7 1/2% Senior Secured Second Lien Notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 20,641,000			450,000,000
Stated interest rate percentage		7.50%
6 3/8% Convertible Senior Notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 245,548,000			0
Debt discount		$ (74,800,000)		$ (79,900,000)
Stated interest rate percentage		6.375%
6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 51,304,000			203,545,000
Stated interest rate percentage		6.375%
5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 58,426,000			314,662,000
Stated interest rate percentage		5.50%
4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 135,960,000			307,978,000
Stated interest rate percentage		4.625%
Future interest payable on senior secured notes
Debt Instrument [Line Items]
Less: current maturities of long-term debt		$ (86,054,000)			(85,303,000)
Long-term Debt and Lease Obligation		$ 78,860,000			$ 164,914,000
[1]	Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $27.0 million and $74.8 million , respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019 .
[2]	Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors .
[3]	Our current maturities of long-term debt as of December 31, 2019 include $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.

Long-Term Debt (Debt Maturity S

Long-Term Debt (Debt Maturity Schedule) (Details 1) $ in Thousands	Dec. 31, 2019USD ($)
Indebtedness repayment schedule
2020	$ 15,323
2021	683,562
2022	532,157
2023	155,293
2024	817,297
Thereafter	78,094
Total indebtedness	$ 2,281,726

Long-Term Debt (Details Textual

Long-Term Debt (Details Textuals)	Apr. 30, 2014USD ($)	Jul. 31, 2019USD ($)	Jun. 30, 2019USD ($)	Aug. 31, 2018USD ($)	Apr. 17, 2018shares	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)	May 31, 2016USD ($)	Feb. 28, 2013USD ($)	Feb. 28, 2011USD ($)	Jan. 31, 2018USD ($)	Dec. 31, 2019USD ($)shares		Sep. 30, 2019USD ($)	Jun. 30, 2018USD ($)shares	Dec. 31, 2019USD ($)shares$ / shares		Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)	May 30, 2018USD ($)	Apr. 18, 2018USD ($)
Senior Secured Bank Credit Facility [Abstract]
Borrowing base												$ 615,000,000				$ 615,000,000
Lender commitments												615,000,000				$ 615,000,000
Maximum senior secured debt to consolidated EBITDAX requirement																2.5
Minimum EBITDAX to consolidated interest requirement																1.25
Current ratio requirement																1
Outstanding borrowings on senior secured bank credit facility												0				$ 0		$ 0
Letters of credit outstanding												$ 87,200,000				$ 87,200,000
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries												100.00%				100.00%
Cash paid for debt repurchases or exchanges			$ 120,000,000									$ 11,200,000		$ 5,300,000
Gain on extinguishment of debt																$ 155,998,000		0	$ 0
Amount of debt exchanged							$ 609,800,000
Amount of debt extinguished						$ 40,800,000	143,600,000
Debt discount												101,767,000	[1]			101,767,000	[1]	0
Unamortized debt issuance costs												$ 14,000,000				$ 14,000,000		19,100,000
Convertible debt instrument, number of equity instruments | shares																90,900,000
Lease period included in long-term transportation service agreement																20 years
Convertible Debt [Abstract]
Issued pursuant to notes conversion, shares | shares					55,200,000
Issued pursuant to notes conversion, value															$ 162,000,000	$ 0		$ 162,004,000	0
Common Stock
Long Term Debt (Textuals) [Abstract]
Issued as part of debt exchange, shares | shares												38,300,000				36,297,217
Convertible Debt [Abstract]
Issued pursuant to notes conversion, shares | shares															55,200,000			55,249,955
Issued pursuant to notes conversion, value																		$ 55,000
3 1/2% Convertible Senior Notes due 2024
Long Term Debt (Textuals) [Abstract]
Face value of notes							84,700,000												84,700,000
Convertible Debt [Abstract]
Convertible debt instrument, amount exchanged															$ 84,700,000
Convertible debt																					$ 0
5% Convertible Senior Notes due 2023
Long Term Debt (Textuals) [Abstract]
Face value of notes						59,400,000					$ 59,400,000
Convertible Debt [Abstract]
Convertible debt instrument, amount exchanged															$ 59,400,000
Convertible debt																				$ 0
9% Senior Secured Second Lien Notes due 2021
Long Term Debt (Textuals) [Abstract]
Face value of notes								$ 614,900,000
Selling price of debt instrument								100.00%
Stated interest rate percentage												9.00%				9.00%
Carrying amount of long-term debt												$ 614,919,000				$ 614,919,000		614,919,000
9 1/4% Senior Secured Second Lien Notes due 2022
Long Term Debt (Textuals) [Abstract]
Face value of notes						74,100,000	381,600,000				$ 74,100,000								$ 381,600,000
Selling price of debt instrument											100.00%
Stated interest rate percentage												9.25%				9.25%
Carrying amount of long-term debt												$ 455,668,000				$ 455,668,000		455,668,000
7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Face value of notes		$ 3,800,000	528,000,000
Debt discount			$ 22,600,000									$ 27,000,000				$ 27,000,000
Selling price of debt instrument		100.00%
Stated interest rate percentage												7.75%				7.75%
Fair value percentage of debt principal at issuance date			94.00%
Debt instrument, effective interest rate percentage			9.39%
Carrying amount of long-term debt												$ 531,821,000				$ 531,821,000		0
7 1/2% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Amount of debt exchanged		$ 4,000,000
Face value of notes				$ 450,000,000
Selling price of debt instrument				100.00%
Stated interest rate percentage												7.50%				7.50%
Carrying amount of long-term debt												$ 20,641,000				$ 20,641,000		450,000,000
6 3/8% Convertible Senior Notes due 2024
Long Term Debt (Textuals) [Abstract]
Face value of notes			$ 245,500,000
Debt discount			$ 79,900,000									$ 74,800,000				$ 74,800,000
Stated interest rate percentage												6.375%				6.375%
Fair value percentage of debt principal at issuance date			67.00%
Debt instrument, effective interest rate percentage			15.31%
Carrying amount of long-term debt												$ 245,548,000				$ 245,548,000		0
Convertible debt instrument, conversion ratio																370
Convertible debt instrument, number of equity instruments																90,900,000
Convertible debt instrument, stock price trigger | $ / shares																$ 2.43
Convertible debt instrument, threshold trading days																10
Convertible debt instrument, threshold consecutive trading days																15
6 3/8% Senior Subordinated Notes due 2021
Long Term Debt (Textuals) [Abstract]
Amount of debt exchanged			$ 152,200,000			11,600,000
Face value of notes										$ 400,000,000
Selling price of debt instrument										100.00%
Stated interest rate percentage												6.375%				6.375%
Redemption price, percentage																100.00%
Carrying amount of long-term debt												$ 51,304,000				$ 51,304,000		203,545,000
5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Debt repurchases, face amount												$ 25,300,000		$ 11,000,000		$ 25,300,000
Amount of debt exchanged			219,900,000			94,200,000	364,000,000
Face value of notes	$ 1,250,000,000
Selling price of debt instrument	100.00%
Stated interest rate percentage												5.50%				5.50%
Carrying amount of long-term debt												$ 58,426,000				$ 58,426,000		314,662,000
4 5/8% Senior Subordinated Notes due 2023
Long Term Debt (Textuals) [Abstract]
Debt repurchases, face amount												$ 75,700,000				$ 75,700,000
Amount of debt exchanged			96,300,000			68,500,000	$ 245,800,000
Face value of notes									$ 1,200,000,000
Selling price of debt instrument									100.00%
Stated interest rate percentage												4.625%				4.625%
Carrying amount of long-term debt												$ 135,960,000				$ 135,960,000		$ 307,978,000
Year 2020
Senior Secured Bank Credit Facility [Abstract]
Total Debt to Consolidated EBITDAX																5.25
Year 2021 | Q1
Senior Secured Bank Credit Facility [Abstract]
Total Debt to Consolidated EBITDAX																4.50
Year 2021 | Q2
Senior Secured Bank Credit Facility [Abstract]
Total Debt to Consolidated EBITDAX																4.5
Year 2021 | Q3
Senior Secured Bank Credit Facility [Abstract]
Total Debt to Consolidated EBITDAX																4.5
Debt Instrument, Redemption, Period One | 9% Senior Secured Second Lien Notes due 2021
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																104.50%
Debt Instrument, Redemption, Period One | 9 1/4% Senior Secured Second Lien Notes due 2022
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																109.25%
Debt Instrument, Redemption, Period One | 7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																103.875%
Debt Instrument, Redemption, Period One | 7 1/2% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																103.75%
Debt Instrument, Redemption, Period One | 5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																101.375%
Debt Instrument, Redemption, Period One | 4 5/8% Senior Subordinated Notes due 2023
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.771%
Debt Instrument, Redemption, Period Two | 9% Senior Secured Second Lien Notes due 2021
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Debt Instrument, Redemption, Period Two | 9 1/4% Senior Secured Second Lien Notes due 2022
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																104.625%
Debt Instrument, Redemption, Period Two | 5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Debt Instrument, Redemption, Period Two | 4 5/8% Senior Subordinated Notes due 2023
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Debt Instrument, Redemption, Period Three | 9 1/4% Senior Secured Second Lien Notes due 2022
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Initial Redemption Period With Proceeds From Equity Offering Member | 7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																107.75%
Percentage of debt principal available to be redeemed																35.00%
Initial Redemption Period With Proceeds From Equity Offering Member | 7 1/2% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																107.50%
Percentage of debt principal available to be redeemed																35.00%
Initial Redemption Period with Make-Whole Premium | 7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Initial Redemption Period with Make-Whole Premium | 7 1/2% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Redemption price, percentage																100.00%
Senior Secured Bank Credit Facility
Senior Secured Bank Credit Facility [Abstract]
Credit facility, unused capacity - commitment fee percentage																0.50%
Senior Secured Bank Credit Facility | Letter of Credit
Senior Secured Bank Credit Facility [Abstract]
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases												100,000,000				$ 100,000,000
Senior Secured Bank Credit Facility | Swingline Loan
Senior Secured Bank Credit Facility [Abstract]
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases												$ 25,000,000				$ 25,000,000
Senior Secured Bank Credit Facility | London Interbank Offered Rate (LIBOR) | Minimum
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on senior secured bank credit facility																2.75%
Senior Secured Bank Credit Facility | London Interbank Offered Rate (LIBOR) | Maximum
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on senior secured bank credit facility																3.75%
Senior Secured Bank Credit Facility | Base Rate | Minimum
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on senior secured bank credit facility																1.75%
Senior Secured Bank Credit Facility | Base Rate | Maximum
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on senior secured bank credit facility																2.75%
Secured Debt
Long Term Debt (Textuals) [Abstract]
Maximum total debt to EBITDA requirement																2.5
Convertible Debt
Long Term Debt (Textuals) [Abstract]
Maximum total debt to EBITDA requirement																2.5
Senior Subordinated Notes
Long Term Debt (Textuals) [Abstract]
Amount of debt exchanged			468,400,000			$ 174,300,000
Maximum total debt to EBITDA requirement																2.5
Notes Repurchases
Long Term Debt (Textuals) [Abstract]
Gain on extinguishment of debt																$ 55,500,000
Portion Of Exchange Related To Senior Secured Notes
Long Term Debt (Textuals) [Abstract]
Gain on extinguishment of debt			0
Portion Of Exchange Related To Senior Secured Notes | 7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Face value of notes		3,800,000	425,400,000
Unamortized debt issuance costs			6,900,000
Portion Of Exchange Related To Senior Secured Notes | 7 1/2% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Amount of debt exchanged		$ 4,000,000	425,400,000
Notes Exchange
Long Term Debt (Textuals) [Abstract]
Gain on extinguishment of debt																$ 100,500,000
Notes Exchange | 7 3/4% Senior Secured Second Lien Notes due 2024
Long Term Debt (Textuals) [Abstract]
Face value of notes			$ 102,600,000
[1]	Consists of discounts related to the issuance during June 2019 of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) of $27.0 million and $74.8 million , respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019 .

Income Taxes (Income Tax Provis

Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax expense (benefit)
Federal	$ 2,645	$ (17,885)	$ (19,485)
State	1,236	1,884	(1,388)
Total current income tax expense (benefit)	3,881	(16,001)	(20,873)
Deferred income tax expense (benefit)
Federal	89,950	93,395	(113,863)
State	10,521	9,839	18,084
Total deferred income tax expense (benefit)	100,471	103,234	(95,779)
Total income tax expense (benefit)	$ 104,352	$ 87,233	$ (116,652)

Income Taxes (Summary of Change

Income Taxes (Summary of Changes in Valuation Allowance) (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Valuation allowance	$ 77,215	$ 51,093	$ 51,134	$ 36,510
Federal	23,124	0	0
State	$ 2,998	$ (41)	$ 14,624

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 2) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets
Loss and tax credit carryforwards - state	$ 52,917	$ 52,366
Business interest expense carryforward	24,513	9,049
Business credit carryforwards	71,555	79,528
Unrecognized gain and original issue discount on debt exchange	41,556	73,937
Accrued liabilities and other reserves	29,788	25,231
Other	18,725	23,208
Valuation allowances	(77,215)	(51,093)	$ (51,134)	$ (36,510)
Total deferred tax assets	161,839	212,226
Deferred tax liabilities
Property and equipment	(569,254)	(492,214)
Derivative contracts	(1,120)	(23,127)
Other	(1,695)	(6,643)
Total deferred tax liabilities	(572,069)	(521,984)
Total net deferred tax liability	$ (410,230)	$ (309,758)

Income Taxes (Schedule of Effec

Income Taxes (Schedule of Effective Tax Rate Reconciliation) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, Amount
Income tax provision calculated using the federal statutory income tax rate	$ 67,475	$ 86,086	$ 16,275
State income taxes, net of federal income tax benefit	7,435	11,968	2,764
Tax shortfall (windfall) on stock-based compensation deduction	1,912	(1,565)	5,567
Valuation allowance	26,122	(42)	5,562
Enhanced oil recovery credits generated	0	(10,818)	(11,307)
Remeasurement of deferreds related to federal tax rate change	0	0	(132,224)
Other	1,408	1,604	(3,289)
Total income tax expense (benefit)	$ 104,352	$ 87,233	$ (116,652)

Income Taxes (Details Textuals)

Income Taxes (Details Textuals) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Valuation Allowance [Line Items]
Loss and tax credit carryforwards - state	$ 52,917,000	$ 52,366,000
Valuation allowance	77,215,000	51,093,000	$ 51,134,000	$ 36,510,000
Federal net operating loss carryforwards	0
Business interest expense carryforward	24,513,000	$ 9,049,000
Enhanced oil recovery credit carryforwards	49,900,000
Research and development credits	21,600,000
Alternative minimum tax credits	6,000,000
Unrecognized Tax Benefits	5,400,000
Business interest expense
Valuation Allowance [Line Items]
Valuation allowance	24,500,000
State of Louisiana, Mississippi and Alabama
Valuation Allowance [Line Items]
Valuation allowance	52,700,000
State of Louisiana
Valuation Allowance [Line Items]
Valuation allowance	41,300,000
State of Mississippi
Valuation Allowance [Line Items]
Valuation allowance	10,600,000
State of Alabama
Valuation Allowance [Line Items]
Valuation allowance	$ 800,000

Stockholders' Equity (Details T

Stockholders' Equity (Details Textuals) - 401(k) Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Contribution Benefit Plans Disclosures [Line Items]
Employer contribution rate	100.00%
Employer's matching contributions	$ 6.3	$ 6.2	$ 7.1
Maximum
Defined Contribution Benefit Plans Disclosures [Line Items]
Employee contribution rate	6.00%

Stock Compensation (Schedule of

Stock Compensation (Schedule of Share-Based Compensation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Abstract]
Stock-based compensation expense included in G&A	$ 12,470	$ 11,951	$ 15,154
Stock-based compensation capitalized	4,018	3,487	4,567
Total cost of stock-based compensation arrangements	16,488	15,438	19,721
Income tax benefit recognized for stock-based compensation arrangements	$ 3,118	$ 2,988	$ 5,759

Stock Compensation (Summary of

Stock Compensation (Summary of SARs Activity) (Details 2) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / sharesshares
Share-based Payment Arrangement, Disclosure [Abstract]
Number of awards outstanding at December 31, 2018 | shares	2,500,885
Weighted average exercise price, December 31, 2018 | $ / shares	$ 10.41
Number of awards, granted | shares	0
Weighted average exercise price, granted | $ / shares	$ 0
Number of awards, exercised | shares	0
Weighted average exercise price, exercised | $ / shares	$ 0
Number of awards, forfeited | shares	0
Weighted average exercise price, forfeited | $ / shares	$ 0
Number of awards, expired | shares	(519,729)
Weighted average exercise price, expired | $ / shares	$ 15.29
Number of awards outstanding at December 31, 2019 | shares	1,981,156
Weighted average exercise price, December 31, 2019 | $ / shares	$ 9.12
Weighted average remaining contractual life of outstanding SARs	1 year 6 months
Aggregate intrinsic value of SARs outstanding | $	$ 0
Exercisable awards at end of period | shares	1,981,156
Weighted average price, exercisable at end of period | $ / shares	$ 9.12
Weighted average remaining contractual life of exercisable SARs	1 year 6 months
Aggregate intrinsic value of exercisable SARs | $	$ 0

Stock Compensation (Summary o_2

Stock Compensation (Summary of Value of SARs) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Intrinsic value of SARs exercised	$ 0	$ 0	$ 0
Grant-date fair value of SARs vested	$ 0	$ 1,095	$ 1,818

Stock Compensation (Summary o_3

Stock Compensation (Summary of Vesting Date Fair Value of Awards - Restricted Stock) (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of restricted stock vested	$ 5,743	$ 23,060	$ 9,325

Stock Compensation (Summary o_4

Stock Compensation (Summary of Restricted Stock) (Details 5) - Restricted Stock	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Nonvested Restricted Stock Outstanding [Line Items]
Nonvested at December 31, 2018 | shares	8,990,578
Weighted average grant-date fair value, December 31, 2018 | $ / shares	$ 3.40
Granted | shares	9,630,155
Weighted average grant-date fair value, granted | $ / shares	$ 1.15
Vested | shares	(4,612,265)
Weighted average grant-date fair value, vested | $ / shares	$ 3.20
Forfeited | shares	(1,601,032)
Weighted average grant-date fair value, forfeited | $ / shares	$ 2.05
Nonvested at December 31, 2019 | shares	12,407,436
Weighted average grant-date fair value, December 31, 2019 | $ / shares	$ 1.91

Stock Compensation (TSR Award A

Stock Compensation (TSR Award Assumptions) (Details 6) - Performance-Based TSR Awards - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value of Performance-Based TSR Awards granted	$ 1.95	$ 2.29	$ 3.42
Risk-free interest rate	2.27%	2.37%	1.49%
Expected life	3 years	3 years	3 years
Expected volatility	77.20%	102.90%	94.70%
Dividend yield	0.00%	0.00%	0.00%

Stock Compensation (Summary o_5

Stock Compensation (Summary of Performance Based Equity Awards) (Details 7) - $ / shares		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance-Based Operational Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested at December 31, 2018		857,812
Weighted average grant-date fair value, December 31, 2018		$ 2.43
Granted	[1]	980,772
Weighted average grant-date fair value, granted		$ 2.13
Vested	[2]	0
Weighted average grant-date fair value, vested		$ 0
Forfeited		0
Weighted average grant-date fair value, forfeited		$ 0
Nonvested at December 31, 2019		1,838,584	857,812
Weighted average grant-date fair value, December 31, 2019		$ 2.27	$ 2.43
Performance-Based TSR Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested at December 31, 2018		3,806,116
Weighted average grant-date fair value, December 31, 2018		$ 2.71
Granted	[1]	2,027,660
Weighted average grant-date fair value, granted		$ 1.95	$ 2.29	$ 3.42
Vested	[2]	(1,357,778)
Weighted average grant-date fair value, vested		$ 1.78
Forfeited		0
Weighted average grant-date fair value, forfeited		$ 0
Nonvested at December 31, 2019		4,475,998	3,806,116
Weighted average grant-date fair value, December 31, 2019		$ 2.65	$ 2.71
Payout percentage		100.00%
Performance-Based Equity Awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage		0.00%
Performance-Based Equity Awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage		200.00%
[1]	Amounts granted reflect the number of performance units granted. The actual payout of the shares may be between 0% and 200% , with any amounts earned above the 100% target levels payable in cash, rather than in shares of Denbury stock, in order to conserve available shares under the Plan.
[2]	During 2019 , the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 100% of target for each vested TSR performance-based award, representing 1,357,778

Stock Compensation (Summary o_6

Stock Compensation (Summary of Vesting Date Fair Value of Awards) (Details 8) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Performance-Based Operational Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date fair value	$ 0	$ 595	$ 1,079
Performance-Based TSR Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting date fair value	$ 2,783	$ 542	$ 227

Stock Compensation (Details Tex

Stock Compensation (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock Compensation Plans (Textuals)
Maximum number of common stock shares authorized for issuance under Plan	61,400,000
Shares available for future awards	13,600,000
Number of awards exercised	0
Stock Appreciation Rights (SARs)
Stock Compensation Plans (Textuals)
Award vesting period	3 years
SARs expiration period	7 years
Total compensation cost to be recognized in future periods	$ 0
Number of awards exercised	0	0	0
Restricted Stock
Stock Compensation Plans (Textuals)
Award vesting period	3 years
Total compensation cost to be recognized in future periods	$ 17.4
Weighted average period over which remaining cost will be recognized	2 years
Performance-based equity awards
Stock Compensation Plans (Textuals)
Total compensation cost to be recognized in future periods	$ 5.7
Weighted average period over which remaining cost will be recognized	1 year 10 months 24 days
Performance-based equity awards | Minimum
Stock Compensation Plans (Textuals)
Award vesting period	1 year 3 months
Payout percentage	0.00%
Performance-based equity awards | Maximum
Stock Compensation Plans (Textuals)
Award vesting period	3 years 3 months
Payout percentage	200.00%

Commodity Derivative Contract_2

Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - Year 2020	Dec. 31, 2019bbl / d$ / Barrel
Swap | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	2,000
Weighted average swap price	60.59
Swap | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	60
Swap | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	61
Swap | LLS
Derivative [Line Items]
Volume per day | bbl / d	4,500
Weighted average swap price	62.29
Swap | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	60.72
Swap | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	64.26
Three-way Collar | Q1-Q2 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	23,000
Weighted average sold put price	48.25
Weighted average floor price	56.95
Weighted average ceiling price	62.83
Three-way Collar | Q1-Q2 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Floor Price	55
Three-way Collar | Q1-Q2 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Cap Price	82.65
Three-way Collar | Q1-Q2 | LLS
Derivative [Line Items]
Volume per day | bbl / d	10,000
Weighted average sold put price	52.85
Weighted average floor price	61.52
Weighted average ceiling price	68.21
Three-way Collar | Q1-Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Floor Price	58
Three-way Collar | Q1-Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Cap Price	87.10
Three-way Collar | Q3-Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	21,000
Weighted average sold put price	48.26
Weighted average floor price	56.85
Weighted average ceiling price	62.68
Three-way Collar | Q3-Q4 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Floor Price	55
Three-way Collar | Q3-Q4 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Cap Price	82.65
Three-way Collar | Q3-Q4 | LLS
Derivative [Line Items]
Volume per day | bbl / d	8,000
Weighted average sold put price	52.75
Weighted average floor price	61.08
Weighted average ceiling price	68.39
Three-way Collar | Q3-Q4 | LLS | Minimum
Derivative [Line Items]
Derivative, Floor Price	58
Three-way Collar | Q3-Q4 | LLS | Maximum
Derivative [Line Items]
Derivative, Cap Price	87.10

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Hierarchy) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	$ 11,936	$ 93,080
Oil derivative contract - long-term assets	0	4,195
Total Assets	11,936	97,275
Oil derivative contracts - current liabilities	(8,346)	0
Total Liabilities	(8,346)
Quoted Prices in Active Markets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	0	0
Oil derivative contract - long-term assets		0
Total Assets	0	0
Oil derivative contracts - current liabilities	0
Total Liabilities	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	8,503	81,621
Oil derivative contract - long-term assets		2,030
Total Assets	8,503	83,651
Oil derivative contracts - current liabilities	(6,522)
Total Liabilities	(6,522)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Oil derivative contracts - current assets	3,433	11,459
Oil derivative contract - long-term assets		2,165
Total Assets	3,433	$ 13,624
Oil derivative contracts - current liabilities	(1,824)
Total Liabilities	$ (1,824)

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of year	$ 13,624	$ 0
Fair value adjustments on commodity derivatives	(8,205)	13,624
Receipt on settlements of commodity derivatives	(3,810)	0
Fair value of Level 3 instruments, end of year	1,609	13,624
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date	$ (556)	$ 13,624

Fair Value Measurements (Leve_2

Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 1,609	$ 13,624	$ 0
Valuation, Income Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 1,609
Valuation, Income Approach | Minimum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Assumptions, Expected Volatility Rate for a Commodity	12.60%
Valuation, Income Approach | Maximum
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Assumptions, Expected Volatility Rate for a Commodity	34.50%

Fair Value Measurements (Detail

Fair Value Measurements (Details Textuals) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs	$ 300
Debt, Fair Value	$ 1,833,100	$ 1,886,100

Commitments and Contingencies (

Commitments and Contingencies (Commitments) (Details Textuals) $ in Millions	Dec. 31, 2019MMcf / d$ / BarrelMMcf	Dec. 31, 2019USD ($)MMcf / dMMcf
Industrial-source CO2
Long-term Purchase Commitment [Line Items]
Term of long-term purchase commitments		9 years
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel	60
Industrial-source CO2 | Minimum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2		$ 14
Industrial-source CO2 | Maximum
Long-term Purchase Commitment [Line Items]
Aggregate purchase obligation of CO2		$ 33
CO2 Volumetric Production Payments and Industrial CO2 Customers
Long-term Purchase Commitment [Line Items]
Significant supply commitment remaining volume committed (MMcf) | MMcf	770,000	770,000
Term of long-term supply arrangement		15 years
Significant supply commitment yearly maximum volume required (MMcf/d) | MMcf / d	257	257
Helium Supply Arrangement
Long-term Purchase Commitment [Line Items]
Term of long-term supply arrangement		20 years
Maximum payment in event of shortfall		$ 46

Commitments and Contingencies_2

Commitments and Contingencies (Details Textuals 2) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Estimated litigation liability	$ 51,200,000	$ 49,400,000
Amount of letter of credit posted as security	87,200,000
Material tax assessments	0
Helium Supply Arrangement
Loss Contingencies [Line Items]
Maximum payment in event of shortfall	46,000,000
Amount of letter of credit posted as security	32,800,000
Other costs associated with the settlement
Loss Contingencies [Line Items]
Estimated litigation liability	$ 5,200,000

Additional Balance Sheet Deta_3

Additional Balance Sheet Details (Details 1) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Receivables [Abstract]
Trade accounts receivable, net	$ 12,630	$ 11,643
Federal income tax receivable, net	2,987	9,037
Commodity derivative settlement receivables	675	2,390
Other receivables	2,026	3,900
Total	$ 18,318	$ 26,970

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, expensed		$ 72,842	$ 50,076	$ 98,261
Cash paid for interest, capitalized		36,671	37,079	30,762
Cash paid for interest, treated as a reduction of debt		85,303	79,606	50,349
Cash paid for income taxes		2,361	492	450
Cash received from income tax refunds		9,820	8,280	13,323
Noncash investing and financing activities
Increase in asset retirement obligations		13,560	4,499	9,565
Increase (decrease) in liabilities for capital expenditures		(17,740)	14,600	3,930
Conversion of convertible senior notes into common stock	$ 162,000	0	162,004	0
Treasury Stock
Other Significant Noncash Transactions [Line Items]
Retirement of treasury stock		$ 0	$ 0	$ 46,562