DENBURY RESOURCES INC, 10-K filed on 2/27/2020
Annual Report
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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    
v3.19.3.a.u2
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 $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.
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Consolidated Balance Sheets (Parenthetical) - USD ($)
$ 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 $86.1 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months.
v3.19.3.a.u2
Consolidated Statements of Operations - USD ($)
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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)
v3.19.3.a.u2
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 CO2 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 CO2 reserves used to compute depletion of CO2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; 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 CO2 reserves nor those related to the cost of constructing CO2 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 CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing
our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly. 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 CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we see a production response to the CO2 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.

CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 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 CO2 (see Tertiary Injection Costs above for further discussion).

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

Pipelines and Plants

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years. Capitalized costs include $117.6 million of CO2 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 CO2 purchase contract with ConocoPhillips to offtake CO2 from the Lost Cabin gas plant in Wyoming and are included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO2 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 CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing 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 CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, 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 CO2 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.
v3.19.3.a.u2
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 CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains 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 CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

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

Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is 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 CO2 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

CO2 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


v3.19.3.a.u2
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

 
 
CO2 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


v3.19.3.a.u2
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.
v3.19.3.a.u2
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 CO2 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 CO2 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 least annually.  We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed
within five to ten years.  Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.
v3.19.3.a.u2
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

v3.19.3.a.u2
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.
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
of Awards
 
Weighted
Average
Exercise Price
 
Weighted Average Remaining Contractual Life
(in years)
 
Aggregate Intrinsic Value
(in thousands)
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
of Shares
 
Weighted
Average
Grant-Date
Fair Value
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
of Awards
 
Weighted
Average
Grant-Date Fair Value
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
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


v3.19.3.a.u2
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.
v3.19.3.a.u2
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
12/31/2019
(in thousands)
 
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.
v3.19.3.a.u2
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 CO2 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 CO2 generally varies depending on the amount of CO2 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 CO2 to our industrial CO2 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 CO2 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 CO2 reserves at December 31, 2019, our current production capabilities and our projected levels of CO2 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.
v3.19.3.a.u2
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


v3.19.3.a.u2
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


v3.19.3.a.u2
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 CO2 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 CO2 reserves used to compute depletion of CO2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; 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 CO2 reserves nor those related to the cost of constructing CO2 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 CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing
our proved oil and natural gas reserves.  The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.  The cost center ceiling test is prepared quarterly. 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 CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.  

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field.  After we see a production response to the CO2 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
CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 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 CO2 (see Tertiary Injection Costs above for further discussion).

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

Pipelines and Plants

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years. Capitalized costs include $117.6 million of CO2 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 CO2 purchase contract with ConocoPhillips to offtake CO2 from the Lost Cabin gas plant in Wyoming and are included in our Consolidated Balance Sheets under the caption “Other assets.” We amortize the CO2 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 CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues.  The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing 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 CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, 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.

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We would not expect the loss of any purchaser to have a material adverse effect upon our operations.
Income Taxes
Income Taxes

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

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

Net Income per Common Share
Net Income 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 CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains 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 CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

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

Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is 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 CO2 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.  Leases with a term of 12 months or less are not recorded on our balance sheet.The majority of our leases contain renewal options, typically exercisable at our sole discretion. We 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.Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term.
Stock Compensation
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.
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.
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.
v3.19.3.a.u2
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



v3.19.3.a.u2
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

CO2 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


v3.19.3.a.u2
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

 
 
CO2 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


v3.19.3.a.u2
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.
v3.19.3.a.u2
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


v3.19.3.a.u2
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

v3.19.3.a.u2
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
)

v3.19.3.a.u2
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
of Awards
 
Weighted
Average
Exercise Price
 
Weighted Average Remaining Contractual Life
(in years)
 
Aggregate Intrinsic Value
(in thousands)
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
of Shares
 
Weighted
Average
Grant-Date
Fair Value
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
of Awards
 
Weighted
Average
Grant-Date Fair Value
 
Number
of Awards
 
Weighted
Average
Grant-Date Fair Value
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
 
%
 
%
 
%

v3.19.3.a.u2
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.
v3.19.3.a.u2
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
12/31/2019
(in thousands)
 
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%

v3.19.3.a.u2
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


v3.19.3.a.u2
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



v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Nature of Ops and Sign. Acctg Policies (Estimated Amortization Expense for Intangibles) (Details 2)
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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).
v3.19.3.a.u2
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
v3.19.3.a.u2
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      
v3.19.3.a.u2
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%
v3.19.3.a.u2
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  
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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  
v3.19.3.a.u2
Leases (Lease Term and Discount Rate) (Details)
Dec. 31, 2019
Rate
Leases [Abstract]  
Weighted average remaining lease term 5 years 8 months 12 days
Weighted average discount rate 6.70%
v3.19.3.a.u2
Leases (Lease Operating Costs) (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
Leases (Supplemental Cash Flow Information Related to Leases) (Details)
$ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Leases (Prior Year-End Schedule of Future Operating Lease Payments) (Details)
$ in Thousands
Dec. 31, 2018
USD ($)
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
v3.19.3.a.u2
Leases (Details Textuals)
$ in Millions
12 Months Ended
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
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.
v3.19.3.a.u2
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
v3.19.3.a.u2
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    
v3.19.3.a.u2
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
v3.19.3.a.u2
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 $ (27,000,000.0) $ (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.
v3.19.3.a.u2
Long-Term Debt (Debt Maturity Schedule) (Details 1)
$ in Thousands
Dec. 31, 2019
USD ($)
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
v3.19.3.a.u2
Long-Term Debt (Details Textuals)
1 Months Ended 2 Months Ended 3 Months Ended 12 Months Ended
Apr. 30, 2014
USD ($)
Jul. 31, 2019
USD ($)
Jun. 30, 2019
USD ($)
Aug. 31, 2018
USD ($)
Apr. 17, 2018
shares
Jan. 31, 2018
USD ($)
Dec. 31, 2017
USD ($)
May 31, 2016
USD ($)
Feb. 28, 2013
USD ($)
Feb. 28, 2011
USD ($)
Jan. 31, 2018
USD ($)
Dec. 31, 2019
USD ($)
shares
Sep. 30, 2019
USD ($)
Jun. 30, 2018
USD ($)
shares
Dec. 31, 2019
USD ($)
shares
$ / shares
Dec. 31, 2018
USD ($)
shares
Dec. 31, 2017
USD ($)
May 30, 2018
USD ($)
Apr. 18, 2018
USD ($)
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                             1.0        
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     $ 120,000,000.0                 $ 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                       $ 14,000,000.0     $ 14,000,000.0 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 $ 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   $ 3,800,000 528,000,000.0                                
Debt discount     $ 22,600,000                 $ 27,000,000.0     $ 27,000,000.0        
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   $ 4,000,000.0                                  
Face value of notes       $ 450,000,000.0                              
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 $ 11,000,000.0   $ 25,300,000        
Amount of debt exchanged     219,900,000     94,200,000 364,000,000.0                        
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   $ 4,000,000.0 425,400,000                                
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 $74.8 million, respectively (see 2019 Debt Reduction Transactions below) as of December 31, 2019.
v3.19.3.a.u2
Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($)
$ 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)
v3.19.3.a.u2
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  
v3.19.3.a.u2
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)    
v3.19.3.a.u2
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)
v3.19.3.a.u2
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 6,000,000.0      
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      
v3.19.3.a.u2
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%    
v3.19.3.a.u2
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
v3.19.3.a.u2
Stock Compensation (Summary of SARs Activity) (Details 2)
$ / shares in Units, $ in Thousands
12 Months Ended
Dec. 31, 2019
USD ($)
$ / shares
shares
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
v3.19.3.a.u2
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
v3.19.3.a.u2
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
v3.19.3.a.u2
Stock Compensation (Summary of Restricted Stock) (Details 5) - Restricted Stock
12 Months Ended
Dec. 31, 2019
$ / shares
shares
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
v3.19.3.a.u2
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%
v3.19.3.a.u2
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 aggregate shares of common stock issued.
v3.19.3.a.u2
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
v3.19.3.a.u2
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 $ 0.0    
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%    
v3.19.3.a.u2
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - Year 2020
Dec. 31, 2019
bbl / 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 60.00
Swap | NYMEX | Maximum  
Derivative [Line Items]  
Derivative, Swap Type, Fixed Price 61.00
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 55.00
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 58.00
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 55.00
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 58.00
Three-way Collar | Q3-Q4 | LLS | Maximum  
Derivative [Line Items]  
Derivative, Cap Price 87.10
v3.19.3.a.u2
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)  
v3.19.3.a.u2
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
v3.19.3.a.u2
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%    
v3.19.3.a.u2
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
v3.19.3.a.u2
Commitments and Contingencies (Commitments) (Details Textuals)
$ in Millions
12 Months Ended
Dec. 31, 2019
MMcf / d
$ / Barrel
MMcf
Dec. 31, 2019
USD ($)
MMcf / d
MMcf
Industrial-source CO2    
Long-term Purchase Commitment [Line Items]    
Term of long-term purchase commitments   9 years
Oil price assumption for obligation estimate ($/Bbl) | $ / Barrel 60  
Industrial-source CO2 | Minimum    
Long-term Purchase Commitment [Line Items]    
Aggregate purchase obligation of CO2   $ 14.0
Industrial-source CO2 | Maximum    
Long-term Purchase Commitment [Line Items]    
Aggregate purchase obligation of CO2   $ 33.0
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   $ 46.0
v3.19.3.a.u2
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 46,000,000.0  
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  
v3.19.3.a.u2
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
v3.19.3.a.u2
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