Denbury (DNRWW) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document And Company Information [Abstract]	'	'	'
Entity Registrant Name	'Denbury Resources Inc.	'	'
Entity Central Index Key	'0000945764	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$5,625,842,252
Entity Common Stock, Shares Outstanding	'	355,982,927	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$12,187	$98,511
Restricted cash	0	1,050,015
Accrued production receivable	262,047	253,131
Trade and other receivables, net	78,295	81,971
Derivative assets	5	19,477
Deferred tax assets	52,754	29,156
Other current assets	9,271	10,493
Total current assets	414,559	1,542,754
Oil and natural gas properties (using full cost accounting)	'	'
Proved properties	8,945,326	6,963,211
Unevaluated properties	780,481	809,154
CO2 properties	1,117,167	1,032,653
Pipelines and plants	2,209,560	2,035,126
Other property and equipment	466,969	417,207
Less accumulated depletion, depreciation, amortization and impairment	-3,668,225	-3,180,241
Net property and equipment	9,851,278	8,077,110
Derivative assets	9,942	36
Goodwill	1,283,590	1,283,590
Other assets	229,368	235,852
Total assets	11,788,737	11,139,342
Current liabilities	'	'
Accounts payable and accrued liabilities	410,543	414,668
Oil and gas production payable	174,677	161,945
Derivative liabilities	53,822	2,842
Current maturities of long-term debt	36,157	36,966
Total current liabilities	675,199	616,421
Long-term liabilities	'	'
Long-term debt, net of current portion	3,260,625	3,104,462
Asset retirement obligations	119,888	102,730
Derivative liabilities	3,413	23,781
Deferred tax liabilities	2,399,294	2,153,452
Other liabilities	28,912	23,607
Total long-term liabilities	5,812,132	5,408,032
Commitments and contingencies (Note 11)	'	'
Stockholders' equity	'	'
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $.001 par value, 600,000,000 shares authorized; 409,215,573 and 406,163,194 shares issued, respectively	409	406
Paid-in capital in excess of par	3,186,714	3,136,461
Retained earnings	2,844,432	2,434,835
Accumulated other comprehensive loss	-276	-348
Treasury stock, at cost, 46,710,896 and 30,601,262 shares, respectively	-729,873	-456,465
Total stockholders' equity	5,301,406	5,114,889
Total liabilities and stockholders' equity	$11,788,737	$11,139,342

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Stockholders' equity	'	'
Preferred stock, par value	$0.00	$0.00
Preferred stock, shares authorized (actual number)	25,000,000	25,000,000
Preferred stock, shares issued (actual number)	0	0
Preferred stock, shares outstanding (actual number)	0	0
Common stock, par value	$0.00	$0.00
Common stock, shares authorized (actual number)	600,000,000	600,000,000
Common stock, shares issued (actual number)	409,215,573	406,163,194
Treasury stock, shares (actual number)	46,710,896	30,601,262

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues and other income	'	'	'
Oil, natural gas, and related product sales	$2,466,234	$2,409,867	$2,269,151
CO2 sales and transportation fees	27,950	26,453	22,711
Interest income and other income	22,943	20,152	17,462
Total revenues and other income	2,517,127	2,456,472	2,309,324
Expenses	'	'	'
Lease operating expenses	730,574	532,359	507,397
Marketing expenses	49,246	52,836	26,047
CO2 discovery and operating expenses	16,916	14,694	14,258
Taxes other than income	176,231	160,016	147,534
General and administrative expenses	145,211	144,019	125,525
Interest, net of amounts capitalized of $78,373, $77,432 and $61,586, respectively	140,709	153,581	164,360
Depletion, depreciation and amortization	509,943	507,538	409,196
Commodity derivatives expense (income)	41,024	-4,834	-52,497
Loss on early extinguishment of debt	44,651	0	16,131
Impairment of assets	0	17,515	22,951
Other expenses	20,242	21,891	4,377
Total expenses	1,874,747	1,599,615	1,385,279
Income before income taxes	642,380	856,857	924,045
Income tax provision	232,783	331,497	350,712
Net Income	$409,597	$525,360	$573,333
Net income per common share	'	'	'
Basic	$1.12	$1.36	$1.45
Diluted	$1.11	$1.35	$1.43
Weighted average common shares outstanding	'	'	'
Basic	366,659	385,205	396,023
Diluted	369,877	388,938	400,958

Consolidated_Statements_of_Ope1

Consolidated Statements of Operations (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Expenses	'	'	'
Interest, capitalized	$79,253	$77,432	$61,586

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Operations (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Net income	$409,597	$525,360	$573,333
Other comprehensive income, net of income tax:	'	'	'
Interest rate lock derivative contracts reclassified to income, net of tax of $40, $43 and $43, respectively	72	70	70
Total other comprehensive income	72	70	70
Comprehensive income	$409,669	$525,430	$573,403

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Operations (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other comprehensive income, net of income tax:	'	'	'
Tax for interest rate lock derivative contracts reclassified to income	$40	$43	$43

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flow from operating activities	'	'	'
Net income	$409,597	$525,360	$573,333
Adjustments to reconcile net income to cash flow from operating activities	'	'	'
Depletion, depreciation and amortization	509,943	507,538	409,196
Deferred income taxes	222,526	255,743	342,463
Stock-based compensation	33,003	29,310	33,190
Commodity derivatives expense (income)	41,024	-4,834	-52,497
Cash receipt (payment) on settlements of commodity derivatives	-662	17,880	2,377
Loss on early extinguishment of debt	44,651	0	16,131
Amortization of debt issuance costs and discounts	14,023	14,695	16,954
Impairment of assets	0	17,515	22,951
Other, net	-2,318	16,917	-4,190
Changes in assets and liabilities, net of effects from acquisitions	'	'	'
Accrued production receivable	-15,085	36,234	-74,781
Trade and other receivables	4,981	45,836	-55,470
Other current and long-term assets	10,462	7,688	-15,817
Accounts payable and accrued liabilities	91,816	5,828	-35,462
Oil and natural gas production payable	12,731	-23,460	54,391
Other liabilities	-15,497	-41,359	-27,955
Net cash provided by operating activities	1,361,195	1,410,891	1,204,814
Cash flow used for investing activities	'	'	'
Oil and natural gas capital expenditures	-900,221	-1,122,615	-1,082,853
Acquisitions of oil and natural gas properties	-9,243	-156,082	-35,305
Cash paid in Riley Ridge acquisition	0	0	-199,263
Bakken exchange transaction	-10,385	281,669	0
CO2 capital expenditures	-93,744	-131,043	-84,789
Pipelines and plants capital expenditures	-184,286	-330,417	-236,133
Purchases of other assets	-65,987	-25,765	-28,838
Net proceeds from sales of oil and natural gas properties and equipment	8,037	34,750	69,370
Net proceeds from sale of short-term investments	0	83,545	0
Other	-19,480	-10,883	-8,147
Net cash used for investing activities	-1,275,309	-1,376,841	-1,605,958
Cash flow provided by (used for) financing activities	'	'	'
Bank repayments	-1,550,000	-1,555,000	-330,000
Bank borrowings	1,190,000	1,870,000	715,000
Repayment of senior subordinated notes	-651,270	0	-525,000
Premium paid on repayment of senior subordinated notes	-36,475	0	-13,137
Net proceeds from issuance of senior subordinated notes	1,200,000	0	400,000
Costs of debt financing	-20,161	-34	-13,123
Common stock repurchase program	-281,958	-251,480	-195,227
Other	-22,346	-17,718	-545
Net cash provided by (used for) financing activities	-172,210	45,768	37,968
Net increase (decrease) in cash and cash equivalents	-86,324	79,818	-363,176
Cash and cash equivalents at beginning of year	98,511	18,693	381,869
Cash and cash equivalents at end of year	$12,187	$98,511	$18,693

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Stockholders' Equity (USD $)	Total	Common Stock ($.001 Par Value)	Paid-In Capital in Excess of par	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock (at cost)
In Thousands, except Share data
Beginning balance at Dec. 31, 2010	$4,380,707	$400	$3,045,937	$1,336,142	($488)	($1,284)
Beginning balance, shares at Dec. 31, 2010	'	400,291,033	'	'	'	78,524
Repurchase of common stock, value	-195,227	'	'	'	'	-195,227
Repurchase of common stock, shares	14,112,610	'	'	'	'	14,112,610
Issued or purchased pursuant to employee stock compensation plans, value	4,688	3	4,685	'	'	'
Issued or purchased pursuant to employee stock compensation plans, shares	'	2,623,962	'	'	'	'
Issued pursuant to employee stock purchase plan, value	11,235	'	-1,623	'	'	12,858
Issued pursuant to employee stock purchase plan, shares	'	11,330	'	'	'	-666,867
Issued pursuant to directors' compensation plan, value	309	'	309	'	'	'
Issued pursuant to directors' compensation plan, shares	'	19,745	'	'	'	'
Stock-based compensation	40,187	'	40,187	'	'	'
Income tax benefit from equity awards	879	'	879	'	'	'
Tax withholding - stock compensation, value	-9,683	'	'	'	'	-9,683
Tax withholding - stock compensation, shares	'	'	'	'	'	441,406
Derivative contracts, net	70	'	'	'	70	'
Net income	573,333	'	'	573,333	'	'
Ending balance at Dec. 31, 2011	4,806,498	403	3,090,374	1,909,475	-418	-193,336
Ending balance, shares at Dec. 31, 2011	'	402,946,070	'	'	'	13,965,673
Repurchase of common stock, value	-266,657	'	'	'	'	-266,657
Repurchase of common stock, shares	16,978,008	'	'	'	'	16,978,008
Issued or purchased pursuant to employee stock compensation plans, value	6,024	3	6,021	'	'	'
Issued or purchased pursuant to employee stock compensation plans, shares	'	3,197,476	'	'	'	'
Issued pursuant to employee stock purchase plan, value	13,260	'	1,607	'	'	11,653
Issued pursuant to employee stock purchase plan, shares	'	'	'	'	'	-815,385
Issued pursuant to directors' compensation plan, value	321	'	321	'	'	'
Issued pursuant to directors' compensation plan, shares	'	19,648	'	'	'	'
Stock-based compensation	37,897	'	37,897	'	'	'
Income tax benefit from equity awards	241	'	241	'	'	'
Tax withholding - stock compensation, value	-8,125	'	'	'	'	-8,125
Tax withholding - stock compensation, shares	'	'	'	'	'	472,966
Derivative contracts, net	70	'	'	'	70	'
Net income	525,360	'	'	525,360	'	'
Ending balance at Dec. 31, 2012	5,114,889	406	3,136,461	2,434,835	-348	-456,465
Ending balance, shares at Dec. 31, 2012	'	406,163,194	'	'	'	30,601,262
Repurchase of common stock, value	-277,768	'	'	'	'	-277,768
Repurchase of common stock, shares	16,468,648	'	'	'	'	16,468,648
Issued or purchased pursuant to employee stock compensation plans, value	5,489	3	5,486	'	'	'
Issued or purchased pursuant to employee stock compensation plans, shares	'	3,038,767	'	'	'	'
Issued pursuant to employee stock purchase plan, value	15,104	'	1,844	'	'	13,260
Issued pursuant to employee stock purchase plan, shares	'	'	'	'	'	-860,901
Issued pursuant to directors' compensation plan, value	344	'	344	'	'	'
Issued pursuant to directors' compensation plan, shares	'	13,612	'	'	'	'
Stock-based compensation	42,091	'	42,091	'	'	'
Income tax benefit from equity awards	488	'	488	'	'	'
Tax withholding - stock compensation, value	-8,900	'	'	'	'	-8,900
Tax withholding - stock compensation, shares	'	'	'	'	'	501,887
Derivative contracts, net	72	'	'	'	72	'
Net income	409,597	'	'	409,597	'	'
Ending balance at Dec. 31, 2013	$5,301,406	$409	$3,186,714	$2,844,432	($276)	($729,873)
Ending balance, shares at Dec. 31, 2013	'	409,215,573	'	'	'	46,710,896

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Significant Accounting Policies [Text Block]	'
	Note 1. Significant Accounting Policies
	Organization and Nature of Operations
	Denbury Resources Inc., a Delaware corporation, is a growing, dividend-paying, domestic oil and natural gas company.  Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary 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) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price allocations, including goodwill.  While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
	Reclassifications
	Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.
	Cash Equivalents
	We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
	Restricted Cash
	Restricted cash at December 31, 2012 consisted of proceeds from the exchange of oil and gas properties with Exxon Mobil Corporation and its wholly-owned subsidiary, XTO Energy Inc., (see Note 2, Acquisitions and Divestitures) previously held by a qualified intermediary and which were restricted for application towards future acquisitions to enable like-kind-exchange transactions for federal income tax purposes, which exchange transactions took place in 2013.
	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 acquisitions, 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 Measurements and Disclosures 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.
	Ceiling Test. 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 the 12-month 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 those costs have previously been incurred by the Company.  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 have a ceiling test write-down during the years ended December 31, 2013, 2012 or 2011.
	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 SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, 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 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.
	During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit ("Riley Ridge"), which contains helium and CO2 reserves (non-hydrocarbon resources) as well as natural gas reserves (a hydrocarbon resource).  It is not possible to separately identify the capitalized costs related to the development of each product in the commingled gas stream; thus, these costs are allocated to each product based on the relative future revenue value of each product line and classified accordingly on the Consolidated Balance Sheets.
	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 reserves is included in the ceiling test as a reduction to future net revenues.  The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.
	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 15 to 50 years.
	Pipelines and plants include the Riley Ridge gas processing facility in southwestern Wyoming. We placed the Riley Ridge gas processing facility in service in the fourth quarter of 2013. Individual components of the plant are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years.
	Property and Equipment – Other
	Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, 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.
	Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability.  Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.
	Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.
	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 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 and are discounted using our credit-adjusted-risk-free rate.  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 Measurements and Disclosures 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 or collars, and fixed price swaps.  Our derivative financial instruments 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 oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.
	Financial Instruments with Off-Balance-Sheet Risk and 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 banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates.  There are no margin requirements with the counterparties of our derivative contracts.
	Goodwill and Other Intangible Assets
	Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units.  However, we have only one reporting unit.  To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value.  Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit.  If it is determined that the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense.  We completed our annual goodwill impairment assessment during the fourth quarter of 2013 and did not record any goodwill impairment during 2013, nor have we recorded a goodwill impairment historically.
	The following table summarizes the changes in goodwill for the years ended December 31, 2013 and 2012:
		Year Ended December 31,
	In thousands	2013			2012
	Beginning of year balance	$	1,283,590		$	1,236,318
	Goodwill related to the Thompson Field acquisition	—			47,272
	End of year balance	$	1,283,590		$	1,283,590
	Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to helium production rights at the Riley Ridge Federal Unit in Wyoming and a CO2 purchase contract with ConocoPhillips to offtake CO2 from the Lost Cabin gas plant in Wyoming. We amortize our helium production rights on a unit-of-production basis over estimated helium reserves and amortize the CO2 contract intangible asset on a straight-line basis over the contract term. Total amortization expense related to these assets was $1.3 million during the year ended December 31, 2013. The following table summarizes the intangible asset value and related accumulated amortization as of December 31, 2013 and 2012:
	In thousands	Helium Production Rights			CO2 Purchase Contract			Total
	31-Dec-13
	Intangible asset value	$	55,266		$	33,931		$	89,197
	Accumulated amortization	—			(1,319		)	(1,319		)
	Net book value as of December 31, 2013	$	55,266		$	32,612		$	87,878
	December 31, 2012
	Intangible asset value	$	55,266		$	33,901		$	89,167
	Accumulated amortization	—			—			—
	Net book value as of December 31, 2012	$	55,266		$	33,901		$	89,167
	At December 31, 2013, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
	In thousands
	2014	$	2,748
	2015	2,843
	2016	2,915
2017	2,915
2018	3,568
The recoverability of the carrying amount of intangible assets is assessed whenever events or changes in circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. An impairment loss would be assessed when estimated undiscounted future cash flows from the operation and disposition of the asset group are less than the carrying amount of the asset group. Measurement of an impairment loss is based on the excess of the carrying amount of the asset group over its fair value. Fair value is measured using discounted cash flows or independent appraisals, as appropriate.
Revenue Recognition
Revenue Recognition. Revenue is recognized at the time oil and natural gas is produced and sold.  Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property.  A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.  As of December 31, 2013 and 2012, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements.  We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date.
Significant Oil and Natural Gas Purchasers. 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 do not expect that the loss of any purchaser would have a material adverse effect upon our operations.  For the year ended December 31, 2013, three purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (33%), Plains Marketing LP (15%), and Eighty-Eight Oil LLC (10%). For the years ended December 31, 2012 and 2011, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (39% and 43% in 2012 and 2011, respectively) and Plains Marketing LP (17% and 16% in 2012 and 2011, respectively).
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 stock options, stock appreciation rights ("SARs"), nonvested restricted stock and nonvested performance equity awards. For each of the three years in the period ended December 31, 2013, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
	Year Ended December 31,
In thousands	2013		2012			2011
Basic weighted average common shares	366,659		385,205			396,023
Potentially dilutive securities:
Restricted stock, stock options, SARs and performance-based equity awards	3,218		3,733			4,935
Diluted weighted average common shares	369,877		388,938			400,958
Basic weighted average common shares excludes 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 all restricted stock is issued and outstanding upon grant).  For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.6 million, 4.1 million and 5.0 million shares for the years ended December 31, 2013, 2012 and 2011, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.
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
Balance Sheet-Offsetting Assets and Liabilities.  In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-11, Disclosure about Offsetting Assets and Liabilities ("ASU 2011-11").  ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013, and have been applied retrospectively for all comparative periods presented.  The adoption of ASU 2011-11 and ASU 2013-01 did not affect our consolidated financial statements, but required additional disclosures in the notes thereto.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions and Divestitures	'
	Note 2. Acquisitions and Divestitures
	Fair Value
	The FASC Fair Value Measurements and Disclosures 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"). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.
	The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs.  Key assumptions may include (1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions (this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs of CO2 (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.
	2013 Acquisition
	Cedar Creek Anticline Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the Cedar Creek Anticline ("CCA") of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips Company ("ConocoPhillips") for $1.05 billion ($1.0 billion after final closing adjustments primarily for revenues and costs of the purchased properties from the January 1, 2013 effective date to the closing date). We closed the acquisition on March 27, 2013, funding the purchase price with a portion of the cash proceeds from the Bakken Exchange Transaction (described below). This acquisition meets the definition of a business under the FASC Business Combinations topic. Accordingly, we estimated the fair value of assets acquired and liabilities assumed as of the closing date of the acquisition, using a discounted future net cash flow model.
	We finalized our estimate of the fair value of assets acquired and liabilities assumed during 2013, after consideration of final closing adjustments, evaluation of oil and natural gas properties, other assets and related asset retirement obligations. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the CCA acquisition:
	In thousands
	Consideration
	Cash consideration (1)		$	1,001,707
	Fair value of assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved properties		783,507
	Unevaluated properties		222,820
	Other assets		2,589
	Asset retirement obligations		(7,209		)
			$	1,001,707
	-1	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.
	For the period from March 27, 2013 to December 31, 2013, we recognized $268.3 million of oil, natural gas, and related product sales from the property interests acquired in the CCA acquisition; during that same period, we recognized $194.2 million of net field operating income (defined as oil, natural gas and related product sales less lease operating expenses, production and ad valorem taxes, and marketing expenses) related to the CCA acquisition.
	2012 Acquisitions and Divestitures
	Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction (the "Bakken Exchange Transaction") with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, "ExxonMobil") in which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash (after closing adjustments), (2) ExxonMobil's operating interests in Webster Field in Texas and Hartzog Draw Field in Wyoming, and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO2 reserves in LaBarge Field in Wyoming.
	This acquisition meets the definition of a business under the FASC Business Combinations topic. We finalized our estimate of the fair value of assets acquired and liabilities assumed during 2013, after consideration of final closing adjustments and evaluation of reserves. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Bakken Exchange Transaction:
	In thousands
	Consideration
	Fair value of net assets transferred		$	1,866,107
	Less: Fair value of assets acquired and liabilities assumed
	Cash (1)		1,277,041
	Oil and natural gas properties
	Proved properties		182,289
	Unevaluated properties		90,690
	CO2 properties		314,505
	Other property and equipment		23,424
	Other assets		477
	Other liabilities		(8,528		)
	Asset retirement obligations		(13,791		)
	Fair value of net assets acquired		$	1,866,107
	-1	See Note 13, Supplemental Cash Flow Information, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust in order to enable a like-kind exchange transaction for federal income tax purposes.
	Thompson Field Acquisition. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after closing adjustments. The field is located in close proximity to Hastings Field (an enhanced oil recovery field that we are currently flooding with CO2), which is the current terminus of the Green Pipeline, which transports CO2 both from the Jackson Dome area near Jackson, Mississippi, and from various anthropogenic sources along the route of the pipeline. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO2 injection.
	This acquisition meets the definition of a business under the FASC Business Combinations topic. The fair values assigned to assets acquired and liabilities assumed in this acquisition have been finalized, and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2012. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson Field acquisition:
	In thousands
	Consideration
	Cash consideration (1)		$	366,179
	Less: Fair value of assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved properties		305,233
	Unevaluated properties		12,023
	Pipelines and plants		2,000
	Other assets		2,957
	Asset retirement obligations		(3,306		)
			318,907
	Goodwill		$	47,272
	-1	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.
	Unaudited Pro Forma Acquisition Information.  The following combined pro forma total revenues and other income and net income are presented as if the previously discussed CCA acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:
			Year Ended December 31,
	In thousands, except per-share data		2013			2012
	Pro forma total revenues and other income		$	2,599,301		$	2,570,829
	Pro forma net income		437,616			582,033
	Pro forma net income per common share
	Basic		$	1.19		$	1.51
	Diluted		1.18			1.5
	Other 2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $68.5 million, after final closing adjustments. The sale had an effective date of January 1, 2012. In February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011. We did not record a gain or loss on these divestitures in accordance with the full cost method of accounting. Certain of our 2012 divestitures were structured as like-kind-exchange transactions for federal income tax purposes. See Note 6, Income Taxes, for further details.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Note 3. Asset Retirement Obligations
	The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2013 and 2012:
			Year Ended December 31,
	In thousands		2013			2012
	Beginning asset retirement obligation		$	106,430		$	93,468
	Liabilities incurred and assumed during period		22,216			50,956
	Revisions in estimated retirement obligations		4,730			5,334
	Liabilities settled and sold during period		(15,523		)	(50,556		)
	Accretion expense		8,448			7,228
	Ending asset retirement obligation		126,301			106,430
	Less: current asset retirement obligation (1)		(6,413		)	(3,700		)
	Long-term asset retirement obligation		$	119,888		$	102,730
	-1	Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.
	Liabilities incurred and assumed generally relate to the drilling of incremental wells and liabilities assumed upon the purchase of additional interests in the CCA during 2013 and the acquisition of Thompson, Webster and Hartzog Draw fields during 2012. Liabilities settled and sold in 2012 include the plugging of old wells in the Tinsley Field and sales of non-core assets located in the Paradox Basin of Utah, Gulf Coast region and Bakken area assets in North Dakota and Montana.
	We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these escrow accounts were $36.0 million and $35.2 million at December 31, 2013 and 2012, respectively.  These balances are primarily invested in U.S. Treasury bonds, are recorded at amortized cost and are included in "Other assets" in our Consolidated Balance Sheets.  The carrying value of these investments approximates their estimated fair market value at December 31, 2013 and 2012.

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment Disclosure [Text Block]	'
	Note 4. Property and Equipment
	The following table presents a summary of our net property and equipment balances as of December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Oil and natural gas properties
	Proved properties		$	8,945,326		$	6,963,211
	Unevaluated properties		780,481			809,154
	Total		9,725,807			7,772,365
	Accumulated depletion and depreciation		(3,219,500		)	(2,827,256		)
	Net oil and natural gas properties		6,506,307			4,945,109
	CO2 properties
	CO2 properties		1,117,167			1,032,653
	Accumulated depletion and depreciation		(150,968		)	(119,784		)
	Net CO2 properties		966,199			912,869
	Pipelines and plants
	CO2 pipelines (1)		1,681,774			1,632,255
	Plants		527,786			402,871
	Total		2,209,560			2,035,126
	Accumulated depletion and depreciation		(134,697		)	(99,185		)
	Net plants and pipelines		2,074,863			1,935,941
	Other property and equipment
	Other property and equipment		466,969			417,207
	Accumulated depletion and depreciation		(163,060		)	(134,016		)
	Net other property and equipment		303,909			283,191
	Net property and equipment		$	9,851,278		$	8,077,110
	-1	Amounts include $48.4 million of CO2 pipelines at December 31, 2013 that were under construction and not subject to depreciation during 2013.
	A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2013, and the year in which the costs were incurred follows:
			December 31, 2013
			Costs Incurred During:
	In thousands		2013			2012			2011		2010 and prior		Total
	Property acquisition costs		$	215,822		$	109,275		$	12,543	$	317,226	$	654,866
	Exploration and development		41,157			22,080			7,408		10,825		81,470
	Capitalized interest		25,222			12,084			6,018		821		44,145
	Total		$	282,201		$	143,439		$	25,969	$	328,872	$	780,481
	Our 2013 property acquisition costs were primarily related to the fair value allocated to the purchase of additional interests in the CCA. Our 2012 property acquisition costs were primarily related to the fair value allocated to our Hartzog Draw and Thompson fields.  Property acquisition costs for 2010 and prior were primarily related to the fair value allocated to CO2 tertiary potential at our Cedar Creek Anticline properties, acquired as part of the merger with Encore Acquisition Company ("Encore"), 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, 2013.  The most significant development costs incurred during 2013, 2012 and 2011 relate to development in preparation for the CO2 flood at Grieve field, which began in 2013. We have not yet recognized proved reserves in this field.
	During 2013, we established proved reserves at Bell Creek Field and, as a result, transferred $417.6 million of costs incurred on these projects into the amortization base. 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 most 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.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Note 5. Long-Term Debt
	The following long-term debt and capital lease obligations were outstanding as of December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Bank Credit Agreement		$	340,000		$	700,000
	9½% Senior Subordinated Notes due 2016, including premium of $9,118		—			234,038
	9¾% Senior Subordinated Notes due 2016, including discount of $13,569		—			412,781
	8¼% Senior Subordinated Notes due 2020		996,273			996,273
	6 3/8% Senior Subordinated Notes due 2021		400,000			400,000
	4 5/8% Senior Subordinated Notes due 2023		1,200,000			—
	Other Subordinated Notes, including premium of $16 and $25, respectively		3,823			3,832
	Pipeline financings		228,167			236,244
	Capital lease obligations		128,519			158,260
	Total		3,296,782			3,141,428
	Less: current obligations		(36,157		)	(36,966		)
	Long-term debt and capital lease obligations		$	3,260,625		$	3,104,462
	The ultimate parent company in our corporate structure, Denbury Resources Inc. ("DRI"), is the sole issuer of all of our outstanding 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; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees of the notes are full and unconditional and joint and several.
	$1.6 Billion Revolving Credit Agreement
	In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. ("JPMorgan"), as administrative agent, and other lenders party thereto (as amended, the "Bank Credit Agreement").  Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 of each year, and additionally upon requested special redeterminations.  The borrowing base is adjusted at the lenders' discretion and is based in part upon external factors over which we have no control (including approval by the lenders party to the Bank Credit Agreement).  If our outstanding credit under the Bank Credit Agreement exceeds the then effective borrowing base, we would be required to repay the excess amount over a period not to exceed four months.  As part of the semi-annual review completed in October 2013 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion effective November 1, 2013, with approval by all of the lenders.  The weighted average interest rate on borrowings outstanding as of December 31, 2013 under the Bank Credit Agreement was 1.9%. Loans under the Bank Credit Agreement mature in May 2016.
	The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of DRI's restricted subsidiaries (which does not include minor subsidiaries) and by the equity interests of such restricted subsidiaries.  In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by DRI's restricted subsidiaries.
	The Bank Credit Agreement contains several restrictive covenants including, among others:
	•	a requirement to maintain a current ratio, as determined under the Bank Credit Agreement, of not less than 1.0 to 1.0;
	•	a requirement to maintain a maximum permitted ratio of consolidated total debt to Consolidated EBITDA (as defined in the Bank Credit Agreement) of DRI and its restricted subsidiaries of not more than 4.25 to 1.0;
	•	a prohibition against incurring debt, subject to permitted exceptions; and
	•	a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts.
	Under the Bank Credit Agreement, we are permitted to make unlimited distributions in the form of repurchases of Denbury common stock and payments of cash dividends on Denbury common stock, provided that (1) prior to and after making any such distribution (a) no default or borrowing base deficiency exists, and (b) we are in compliance with the first two financial covenants described immediately above (calculated on a pro forma basis after giving effect to the making of any such distribution), and (2) we have minimum availability of at least 10% of our borrowing base on the date such distribution is made.
	Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding credit in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.  Eurodollar loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 1.5% to 2.5% based on the ratio of outstanding credit to the borrowing base, and base rate loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 0.5% to 1.5% based on the ratio of outstanding credit to the borrowing base.  The "Eurodollar rate" for any interest period (either one, two, three, six, and, if available to all lenders, nine or twelve months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period.  The "base rate" is calculated as the highest of (1) the annual rate of interest announced by JPMorgan as its "prime rate," (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) for a one-month interest period plus 1.0%.  We incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding credit to the borrowing base, on the unused availability under the Bank Credit Agreement.
	Senior Subordinated Notes
	Repurchase and Redemption of 9½% Notes and 9¾% Notes. In January 2013, we commenced cash tender offers to purchase the outstanding $426.4 million principal amount of our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes") at 105.425% of par and the outstanding $224.9 million principal amount of our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes") at 106.869% of par. During February 2013, we accepted for purchase $191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the outstanding 9½% Notes. The purchases under these tender offers were funded by a portion of the proceeds received in February 2013 from the issuance of our 4 5/8% Senior Subordinated Notes due 2023 (the "2023 Notes"). In March 2013, we repurchased all of the remaining $234.7 million principal amount outstanding of our 9¾% Notes at 104.875% of par. In May 2013, we repurchased all of the remaining $38.2 million principal amount outstanding of our 9½% Notes at 104.75% of par.
	We recognized a loss associated with the debt repurchases of $44.7 million during the year ended December 31, 2013, consisting of both premium payments made to repurchase or redeem the 9¾% Notes and 9½% Notes and the elimination of unamortized debt issuance costs, discounts and premiums related to these notes. The loss is included in our Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt".
	8¼% Senior Subordinated Notes due 2020. In February 2010, we issued $1.0 billion of 8¼% Senior Subordinated Notes due 2020 (the "2020 Notes") for net proceeds after underwriting discounts and commissions of $980 million.  The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par.  We subsequently redeemed $3.7 million principal amount of the 2020 Notes, as required under the indenture governing the 2020 Notes.
	The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year.  We may redeem the 2020 Notes in whole or in part at our option beginning February 15, 2015, at a redemption price of 104.125% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. Prior to February 15, 2015, we may redeem 100% of the principal amount of the 2020 Notes at a price equal to 100% of the principal amount plus a "make-whole" premium and accrued and unpaid interest.  The 2020 Notes are not subject to any sinking fund requirements.
	6 3/8% Senior Subordinated Notes due 2021. In February 2011, we issued $400 million of 6 3/8% Senior Subordinated Notes due 2021 ("2021 Notes").  The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par.  The net proceeds of $393 million were used to repurchase a portion of our 7½% Senior Subordinated Notes due 2013 (the "2013 Notes") and 7½% Senior Subordinated Notes due 2015 (the "2015 Notes") (see 2011 Redemption of 2013 Notes and 2015 Notes below).
	The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year.  We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at a redemption price of 103.188% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. Prior to August 15, 2014, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% of par with the proceeds of certain equity offerings.  In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a "make-whole" premium and accrued and unpaid interest.  The 2021 Notes are not subject to any sinking fund requirements.
	4 5/8% Senior Subordinated Notes due 2023. In February 2013, we issued $1.2 billion of 2023 Notes. The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. The net proceeds, after issuance costs, of $1.18 billion were used to repurchase or redeem our 9½% Notes and 9¾% Notes (see Repurchase and Redemption of 9½% Notes and 9¾% Notes above) and to pay down a portion of outstanding borrowings under our Bank Credit Agreement.
	The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year, commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at a redemption price of 102.313% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture. Prior to January 15, 2016, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2023 Notes at a redemption price of 104.625% of par with the proceeds of certain equity offerings. In addition, at any time prior to January 15, 2018, we may redeem 100% of the principal amount of the 2023 Notes at a redemption price equal to 100% of the principal amount plus a "make-whole" premium and accrued and unpaid interest.
	Restrictive Covenants in Indentures for Senior Subordinated Notes. Each of the indentures for the 2020 Notes, 2021 Notes and 2023 Notes contains certain covenants which are generally consistent and which 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 indenture for the 2023 Notes (the "2023 Indenture") permits us in certain circumstances to make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (both as defined in the 2023 Indenture) of at least 2.5 to 1 (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 2023 Indenture until the 2020 Notes and 2021 Notes have been redeemed or retired.
	2011 Redemption of 2013 Notes and 2015 Notes. Pursuant to cash tender offers, during 2011 we repurchased $225 million in principal of our 2013 Notes and $300 million in principal of our 2015 Notes. We recognized a $16.1 million loss during the year ended December 31, 2011 associated with the debt repurchases, which is included in our Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt".
	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 lease, and the Free State Pipeline included a long-term transportation service agreement.  We recorded both of these transactions as financing 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 effective interest method over the term of each related facility.  Remaining unamortized debt issuance costs were $58.9 million and $56.5 million at December 31, 2013 and 2012, respectively.  These balances are included in "Other assets" in our Consolidated Balance Sheets.
	Indebtedness Repayment Schedule
	At December 31, 2013, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
	In thousands
	2014		$	36,156
	2015		37,634
	2016		377,933
	2017		36,855
	2018		31,899
	Thereafter		2,776,288
	Total indebtedness		$	3,296,765

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Note 6. Income Taxes
	Our income tax provision (benefit) is as follows:
		Year Ended December 31,
	In thousands	2013			2012			2011
	Current income tax expense (benefit)
	Federal	$	393		$	57,720		$	(12,552	)
	State	9,864			18,034			20,801
	Total current income tax expense	10,257			75,754			8,249
	Deferred income tax expense (benefit)
	Federal	222,559			239,862			329,715
	State	(33		)	15,881			12,748
	Total deferred income tax expense	222,526			255,743			342,463
	Total income tax expense	$	232,783		$	331,497		$	350,712
	For federal income tax purposes, we structured the 2012 divestitures of our Bakken area assets and certain non-core assets as like-kind-exchange transactions for interests acquired in Thompson, Webster, Hartzog Draw and LaBarge fields in 2012 and the CCA Acquisition in 2013 (see Note 2, Acquisitions and Divestitures), thereby deferring the majority of the taxable gain on those divestitures. The increase in current taxes during 2012 is primarily due to the taxable gain recognized in the Bakken Exchange Transaction that we were unable to defer through a like-kind-exchange transaction.
	At December 31, 2013, we had tax-effected federal net operating loss carryforwards ("NOLs") totaling $20.2 million, state NOLs totaling $41.4 million, an estimated $15.0 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits.  Our state NOLs expire in various years, starting in 2018, although most do not begin to expire until 2024. Our enhanced oil recovery credits will begin to expire in 2025.
	At December 31, 2013, we had $13.0 million of excess tax benefits related to stock-based compensation that was not recorded as an increase to additional paid-in capital in the period that the stock award vested and/or was exercised. At the time these excess tax benefits reduce current taxes payable and thus, are deemed to be realized by the Company, a corresponding increase to additional paid-in capital will be recognized.
	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, 2013 and 2012 balance sheet dates.  We believe that we will be able to realize all of our deferred tax assets at December 31, 2013, and therefore, have provided no valuation allowance against our deferred tax assets.
	Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
		December 31,
	In thousands	2013			2012
	Deferred tax assets
	Loss carryforwards – federal	$	20,247		$	—
	Loss carryforwards – state	41,379			35,007
	Tax credit carryover	34,837			34,837
	Derivative contracts	21,341			7,252
	Enhanced oil recovery credit carryforwards	14,974			17,346
	Stock-based compensation	34,635			28,387
	Other	37,679			37,226
	Total deferred tax assets	205,092			160,055
	Deferred tax liabilities
	Property and equipment	(2,541,426		)	(2,277,388		)
	Other	(10,206		)	(6,963		)
	Total deferred tax liabilities	(2,551,632		)	(2,284,351		)
	Total net deferred tax liability	$	(2,346,540	)	$	(2,124,296	)
	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	2013			2012			2011
	Income tax provision calculated using the federal statutory income tax rate	$	224,833		$	299,900		$	323,416
	State income taxes, net of federal income tax benefit	13,518			30,955			29,555
	Effect of statutory rate change	(4,178		)	(429		)	(578		)
	Other	(1,390		)	1,071			(1,681		)
	Total income tax expense	$	232,783		$	331,497		$	350,712
	We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  Our income tax returns for tax years ending 2010 through 2012 currently remain subject to examination by the appropriate taxing authorities. We have not paid any significant interest or penalties associated with our income taxes.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Stockholders' Equity	'
	Note 7. Stockholders' Equity
	Stock Repurchase Program
	In October 2011, we commenced a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors.  During 2012 and 2013, the Board of Directors increased the dollar amount of Denbury common shares that could be purchased under the program to an aggregate of $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any time.  We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.  The following table presents a summary of repurchases under our share repurchase program:
		Total repurchases since inception		Year Ended December 31,
	Dollar amounts in thousands, except per-share data			2013		2012		2011
	Total amount repurchased	$	739,652	$	277,768	$	266,657	$	195,227
	Weighted average price per share	$	15.55	$	16.87	$	15.71	$	13.83
	Denbury common stock repurchased (shares)	47,559,266		16,468,648		16,978,008		14,112,610
	As of December 31, 2013, we were authorized to repurchase an additional $422.3 million of common stock under this repurchase program. We account for treasury stock using the cost method and include treasury stock as a component of stockholders’ equity. See Note 14, Subsequent Events, for additional information.
	Employee Stock Purchase Plan
	We have an Employee Stock Purchase Plan that is authorized to issue up to 11,900,000 shares of common stock.  As of December 31, 2013, there were 1,601,230 authorized shares remaining to be issued under the plan.  In accordance with the plan, eligible employees may contribute up to 10% of their base salary, and we match 75% of their contribution.  The combined funds are used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter.  We recognize compensation expense for the 75% Company match portion, which totaled $6.5 million, $5.7 million and $4.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.  This plan is administered by the Compensation Committee of our Board of Directors.
	401(k) Plan
	We offer a 401(k) plan to which employees may contribute tax-deferred 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 2013, 2012 and 2011, our matching contributions to the 401(k) Plan were approximately $9.0 million, $8.0 million and $7.1 million, respectively.

Stock_Compensation_Plans

Stock Compensation Plans	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	'
	Note 8. Stock Compensation Plans
	Stock Incentive Plans
	We have two stock compensation plans.  The first plan (providing only for the issuance of stock options) has been in existence since 1995 (the "1995 Plan") and expired in August 2005 (although options granted under the 1995 Plan prior to that time can remain outstanding for up to 10 years).  The second plan, the 2004 Omnibus Stock and Incentive Plan (the "2004 Plan"), was approved by the stockholders in May 2004 and will expire in May 2024.  The 2004 Plan provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, SARs settled in stock, and performance awards that may be issued to officers, employees, directors and consultants.  Awards covering a total of 34.5 million shares of common stock have been authorized for issuance pursuant to the 2004 Plan, of which awards covering no more than 27.2 million shares may be issued in the form of restricted stock or performance-vesting awards.  At December 31, 2013, 10.8 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 vesting awards.  Our incentive compensation program is administered by the Compensation Committee of our Board of Directors.
	Prior to January 1, 2006, we granted incentive and non-qualified stock options to our employees.  Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock options.  The stock options and SARs generally become exercisable over a three- or four-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 stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the plan, or one year after the death of the optionee.  The stock options and SARs are granted at the fair market value at the time of grant, which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant.
	Holders of restricted stock awards have the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met.  Beginning in 2014, restricted stock awards granted by the Company provide the holders with forfeitable dividend rights until the award vests. Restricted stock awards vest over three-to-four-year vesting periods, with the specific terms of vesting determined at the time of grant.
	Annually, the Board of Directors grants performance-based equity awards to officers of Denbury.  These performance-based awards generally vest over 1.25 to 3.25 years and the number of performance-based shares earned (and eligible to vest) during the performance period will depend upon two sets of factors: (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 number of shares will be earned if the maximum target levels are met.  If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned.  Performance-based Operational Awards are valued using the fair market value of Denbury stock on the grant date, and Performance-based TSR Awards are valued using a Monte Carlo simulation.
	Stock-based compensation expense associated with our field employees is included in "Lease operating expense," while such expense associated with non-field employees 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.
	Stock-based compensation costs for the years ended December 31, 2013, 2012 and 2011, are as follows:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Stock-based compensation expensed:
	General and administrative expenses		$	30,429			$	26,463			$	30,256
	Lease operating expenses		2,574				2,847				2,621
	Other expenses		—				—				313
	Total stock-based compensation expensed		33,003				29,310				33,190
	Stock-based compensation capitalized		9,088				8,587				6,998
	Total cost of stock-based compensation arrangements		$	42,091			$	37,897			$	40,188
	Income tax benefit recognized for stock-based compensation arrangements		$	12,541			$	11,284			$	12,612
	Stock Options and SARs
	The fair value of each SAR award is estimated on the date of grant using the Black-Scholes option pricing model with the assumptions noted in the following table.  The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.  The expected life of stock options and SARs granted was derived from examination of our historical option grants and subsequent exercises.  The contractual terms (cliff vesting and graded vesting) are evaluated separately for the expected life, as the exercise behavior for each is different.  Expected volatilities are based on the historical volatility of our common stock.  Implied volatility was not used in this analysis, as our tradable call option terms are short and the trading volume is low.
			2013				2012				2011
	Weighted average fair value of SARs granted		$	6.72			$	8.9			$	9.68
	Risk-free interest rate		0.67		%		0.79		%		1.74		%
	Expected life		3.6 to 4.8 years				4.0 to 5.0 years				4.0 to 5.0 years
	Expected volatility		50.4		%		64.9		%		63.3		%
	Dividend yield		—		%		—		%		—		%
	The following is a summary of our stock option and SAR activity:
			Number			Weighted				Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
			of Awards			Average				(in years)		(in thousands)
						Exercise Price
	Outstanding at December 31, 2012		10,445,135			$	14.75
	Granted		720,859			16.95
	Exercised		(1,970,426	)		9.33
	Forfeited		(113,509	)		17.31
	Expired		(95,144	)		22.74
	Outstanding at December 31, 2013		8,986,915			16				3.3		$	19,319
	Exercisable at end of period		6,632,141			$	15.51			2.7		$	18,970
	The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair value of stock options and SARs vested:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Intrinsic value of stock options exercised		$	17,287			$	17,315			$	20,463
	Grant-date fair value of stock options and SARs vested		12,852				26,391				11,416
	As of December 31, 2013, there was $8.0 million of total compensation cost to be recognized in future periods related to nonvested stock option and SAR share-based compensation arrangements.  The cost is expected to be recognized over a weighted-average period of 1.7 years.  The following is a summary of cash received from stock option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock options and SARs:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Cash received from stock option exercises		$	5,487			$	6,022			$	4,685
	Tax benefit realized for the exercises of stock options and SARs		437				458				539
	Restricted Stock – 2004 Plan
	As of December 31, 2013, there was $30.6 million of unrecognized compensation expense related to nonvested restricted stock grants.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.1 years.  The following is a summary of the total vesting date fair value of restricted stock under the 2004 Plan:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Fair value of restricted stock vested		$	21,529			$	22,332			$	12,355
	A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes during the year ended December 31, 2013 is presented below:
			Number			Weighted
			of Shares			Average
						Grant-Date
						Fair Value
	Nonvested at December 31, 2012		3,406,207			$	15.6
	Granted		1,805,467			16.96
	Vested		(1,310,347	)		16.21
	Forfeited		(165,917	)		17.23
	Nonvested at December 31, 2013		3,735,410			15.97
	Restricted Stock – Legacy Encore Plan
In February 2010, prior to the consummation of the merger with Encore, Encore issued a restricted stock grant to its employees under the Encore Acquisition Company 2008 Incentive Stock Plan ("Encore Plan").  At the time of the merger with Encore, the shares were converted into shares of Denbury restricted stock.  The shares vest ratably over a four-year graded vesting period; however, legacy Encore employees who terminated their employment for Good Reason, as defined by Encore’s legacy Employee Severance Protection Plan, automatically vested in their awards upon termination.  The remaining nonvested restricted stock issued under the Encore Plan is scheduled to vest during the first quarter of 2014. The following is a summary of the total vesting date fair value of restricted stock under the Encore Plan:
		Year Ended December 31,
In thousands		2013				2012				2011
Fair value of restricted stock vested		$	512			$	584			$	2,259
A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2013 is presented below:
		Number			Weighted
		of Shares			Average
					Grant-Date
					Fair Value
Nonvested at December 31, 2012		56,258			$	15.43
Vested		(31,140	)		15.43
Forfeited		(3,377	)		15.43
Nonvested at December 31, 2013		21,741			15.43
Performance-Based Equity Awards
During 2013 and 2012, we granted Performance-Based Operational Awards and Performance-Based TSR Awards to our officers. As of December 31, 2013, there was $5.4 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 1.6 years.  The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:
		Year Ended December 31,
		2013				2012
Weighted average fair value of Performance-based TSR Award granted		$	20.08			$	24.68
Risk-free interest rate		0.41		%		0.42		%
Expected life		3.0 years				2.8 years
Expected volatility		42.3		%		45.2		%
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, 2013 is as follows:
		Performance-Based							Performance-Based
		Operational Awards							TSR Awards
		Number			Weighted				Number			Weighted
		of Awards			Average				of Awards			Average
					Grant-Date Fair Value							Grant-Date Fair Value
Nonvested at December 31, 2012		100,193			$	17.27			86,917			$	24.68
Granted		215,258			16.77				209,474			20.08
Vested (1)		(100,193	)		17.27				—			—
Forfeited		(5,784	)		16.77				—			—
Nonvested at December 31, 2013		209,474			16.77				296,391			21.43
-1	During 2013, the 2012 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 136% of the number of target-level shares.
The following is a summary of the total vesting date fair value of performance-based equity awards:
		Year Ended December 31,
In thousands		2013				2012				2011
Vesting date fair value of Performance-based Operational Awards		$	2,541			$	2,191			$	10,892

Commodity_Derivative_Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts	'
	Note 9. 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 cash settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our Consolidated Statements of Operations.
	From time to time, we enter 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.  We do not hold or issue derivative financial instruments for trading purposes.  These contracts have consisted of price floors, collars and fixed price swaps.  The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices.  We currently employ a strategy to hedge a portion of our forecasted production approximately 18 months to two years in the future from the current quarter, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
	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. As of December 31, 2013, 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, none of which are classified as hedging instruments:
	Year		Months	Type of Contract	Pricing Index	Volume (2)	Contract Prices (1)
							Range				Weighted Average Price
											Swap		Floor		Ceiling
	Oil Contracts:
	2014		Jan – Mar	Swap	NYMEX	58,000	$	91.67	–	95.95	$	93.53	$	—	$	—
			Apr – June	Swap	NYMEX	58,000		91.67	–	95.95	93.53		—		—
			July – Sept	Swap	NYMEX	58,000		90	–	93.5	92.52		—		—
			Oct – Dec	Swap	NYMEX	58,000		90	–	93.5	92.52		—		—
	2015		Jan – Mar	Collar	NYMEX	38,000	$	80	–	100.9	$	—	$	80	$	96.96
			Jan – Mar	Collar	LLS	20,000		85	–	104	—		85		101.45
			Apr – June	Collar	NYMEX	38,000		80	–	95.25	—		80		94.62
			Apr – June	Collar	LLS	20,000		85	–	103	—		85		102.01
			July – Sept	Collar	NYMEX	38,000		80	–	95.25	—		80		95.04
			July – Sept	Collar	LLS	20,000		85	–	102.6	—		85		100.69
	Natural Gas Contracts:
	2014		Jan – Dec	Collar	NYMEX	14,000	$	4	–	4.47	$	—	$	4	$	4.45
	-1	Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
	-2	Contract volumes are stated in Bbl/d and MMBtu/d for oil and natural gas contracts, respectively.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Note 10. Fair Value Measurements
	The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (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 market 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 and natural gas derivatives that are based on NYMEX pricing.  Our swap contracts are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, including 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 from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  At December 31, 2013, instruments in this category include non-exchange-traded oil collars that are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued using the Black-Scholes model, which is described above. 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. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease in implied volatility would result in a change of approximately $0.1 million in the fair value of these instruments as of December 31, 2013.
	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, 2013 and 2012:
			Fair Value Measurements Using:
			Quoted Prices		Significant			Significant
			in Active		Other			Unobservable
			Markets		Observable			Inputs
					Inputs
	In thousands		(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2013
	Assets:
	Oil and natural gas derivative contracts – current		$	—	$	5		$	—		$	5
	Oil and natural gas derivative contracts – long-term		—		3,034			6,908			9,942
	Total Assets		$	—	$	3,039		$	6,908		$	9,947
	Liabilities:
	Oil and natural gas derivative contracts – current		$	—	$	(53,822	)	$	—		$	(53,822	)
	Oil and natural gas derivative contracts – long-term		—		(3,214		)	(199		)	(3,413		)
	Total Liabilities		$	—	$	(57,036	)	$	(199	)	$	(57,235	)
	December 31, 2012
	Assets:
	Oil and natural gas derivative contracts – current		$	—	$	19,477		$	—		$	19,477
	Oil and natural gas derivative contracts – long-term		—		36			—			36
	Total Assets		$	—	$	19,513		$	—		$	19,513
	Liabilities:
	Oil and natural gas derivative contracts – current		$	—	$	(2,659	)	$	—		$	(2,659	)
	Oil and natural gas derivative contracts – long-term		—		(23,781		)	—			(23,781		)
	Total Liabilities		$	—	$	(26,440	)	$	—		$	(26,440	)
	The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2013 and 2012:
			Year Ended December 31,
	In thousands		2013		2012
	Fair value of Level 3 instruments, beginning of year		$	—	$	23,950
	Fair value adjustments on commodity derivatives		6,709		3,921
	Receipt on settlements of commodity derivatives		—		(27,871		)
	Fair value of Level 3 instruments, end of year		$	6,709	$	—
	The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date		$	6,709	$	—
	Since we do not use 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.
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	During 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of an entity that was created to develop a gasification plant (in which we would offtake its CO2 to use in our tertiary oil operations) as a result of this project not moving forward. This charge is classified as "Impairment of assets" in the Consolidated Statement of Operations for the year ended December 31, 2012.
	Other Fair Value Measurements
	The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.  We use a market approach to determine fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices.  The estimated fair value of our total long-term debt as of December 31, 2013 and 2012, excluding pipeline financing and capital lease obligations, is $2,956.8 million and $2,956.9 million, respectively.  We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Note 11. Commitments and Contingencies
	Leases
	We lease office space, equipment and vehicles that have non-cancelable lease terms.  Currently, our outstanding leases have terms up to 12 years.  We have subleased part of the office space included in our operating leases for which we received rental payments. The following table summarizes operating lease payments paid and received during the periods indicated:
		Year Ended December 31,
	In thousands	2013			2012		2011
	Operating lease payments	$	37,211		$	33,606	$	52,317
	Sublease rental receipts	2,237			2,685		2,398
	In addition, we expect to receive approximately $14.6 million for 2014 through 2019 under these sublease agreements.
	The following table summarizes by year the remaining non-cancelable future payments under these leases as of December 31, 2013:
	In thousands	Pipeline
		and Capital Leases
	2014	$	62,929
	2015	62,254
	2016	60,819
	2017	55,409
	2018	50,750
	Thereafter	280,272
	Total minimum lease payments	572,433
	Less: Amount representing interest	(215,748		)
	Present value of minimum lease payments	$	356,685
	In thousands	Operating
		Leases
	2014	$	11,695
	2015	12,542
	2016	12,510
	2017	12,774
	2018	12,730
	Thereafter	67,832
	Total minimum lease payments	$	130,083
	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 20 years.  The price we will pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil.  Our annual commitment under these contracts could range from $100 million to $170 million per year, assuming a $90 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, plus we have a CO2 delivery obligation to Genesis related to three CO2 volumetric production payments ("VPPs"). Based upon the maximum amounts deliverable as stated in the industrial contracts and the VPPs, we estimate that we may be obligated to deliver up to 367 Bcf of CO2 to these customers over the next 15 years. The maximum volume required in any given year is approximately 119 MMcf/d, which we judge to be minor given the size of our Jackson Dome proven CO2 reserves at December 31, 2013, our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program.
	In conjunction with the August 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third-party purchaser.  After the commencement date, the contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after start-up of the Riley Ridge gas processing facility, which, if not supplied in accordance with the terms of the contract, may obligate us to compensate the third-party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year, or $46.0 million over the term of the contract.
	Delhi Field Release
	In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was discovered and reported within an area of the Denbury-operated Delhi Field located in northern Louisiana.  Denbury immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We have determined that the release originated from one or more wells in the affected area of the field that we believed had been previously and properly plugged and abandoned by a prior operator of the field. We completed our remediation efforts during the fourth quarter of 2013; however, we will continue to monitor the area to ensure the remediation efforts were successful.
	During the year ended December 31, 2013, we recorded $114.0 million of lease operating expenses related to this release in our Consolidated Statement of Operations, and as of December 31, 2013, we had a corresponding $22.0 million liability classified as "Accounts payable and accrued liabilities" in our Consolidated Balance Sheet. These expenses represent our current estimate of the costs related to this release, including remediation costs, based on actual costs incurred through December 31, 2013 of approximately $92.0 million, plus the Company's estimate of future costs related to the satisfaction of known claims and liabilities. Due to the possibility of new claims being asserted in the future in connection with the release, as well as variability in the estimated cost to continue to monitor the area to ensure the remediation efforts were successful, we cannot reliably estimate at this time the full extent of the costs that may ultimately be incurred by the Company related to this release. Although the Company maintains insurance policies that we believe cover certain of the costs, damages and claims related to the release, and we currently and preliminarily estimate that one-third to two-thirds of our current cost estimate may be recoverable under such insurance policies, we have not reached any agreement with our insurance carriers as to recoverable amounts, and accordingly have not recognized any insurance recoveries in our financial statements as of December 31, 2013. Insurance recoveries will be recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.
	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 or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties.  If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs.  We provide accruals for litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
	Other Contingencies
	We are subject to audits in the various states in which we operate for sales and use taxes and severance taxes, and from time to time receive assessments for potential taxes that we may owe.  In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.
	We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

Additional_Balance_Sheet_Detai

Additional Balance Sheet Details	12 Months Ended
	Dec. 31, 2013
Disclosure Text Block [Abstract]	'
Supplemental Balance Sheet Disclosures [Text Block]	'
	Note 12. Additional Balance Sheet Details
	Allowance for Doubtful Accounts
	We record an allowance for doubtful accounts for receivables that we determine to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against "Trade and other receivables" on the Consolidated Balance Sheets, was $0.3 million at December 31, 2013 and 2012.
	Accounts Payable and Accrued Liabilities
		December 31,
	In thousands	2013		2012
	Accrued exploration and development costs	$	100,564	$	109,939
	Accrued interest	68,871		60,698
	Accounts payable	63,263		86,051
	Accrued lease operating expenses	59,762		23,862
	Accrued compensation	55,043		48,451
	Taxes payable	28,019		27,523
	Other	35,021		58,144
	Total	$	410,543	$	414,668

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Cash Flow, Supplemental Disclosure	'
	Note 13. Supplemental Cash Flow Information
	Supplemental Cash Flow Information
			Year Ended December 31,
	In thousands		2013			2012			2011
	Supplemental cash flow information:
	Cash paid for interest, expensed		$	117,442		$	137,950		$	137,259
	Cash paid for interest, capitalized		79,253			77,432			60,540
	Cash paid for income taxes		28,895			99,194			45,912
	Cash received from income tax refunds		(17,087		)	(38,004		)	(24,677		)
	Noncash investing activities:
	Increase in asset retirement obligations		26,946			56,290			24,694
	Increase (decrease) in liabilities for capital expenditures		(18,321		)	(26,882		)	74,697
	Increase in restricted cash (1)		—			1,262,559			—
	Decrease in restricted cash (2)		1,050,328			212,544			—
	-1	During 2012, $212.5 million of proceeds from the sale of certain non-core assets in the Gulf Coast Region and $1.05 billion of the cash proceeds from the Bakken Exchange Transaction were paid by the respective purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.
	-2	During 2012 and 2013, proceeds from the sales of our oil and natural gas property dispositions in 2012, which were held by a qualified intermediary, were released in 2012 to fund the Thompson Field acquisition and in 2013 primarily to fund a portion of the CCA acquisition and certain post-closing costs under the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Note 14. Subsequent Events
	Stock Repurchase Program
	Between January 1, 2014 and February 20, 2014, the Company repurchased an additional 11.8 million shares of Denbury common stock under the share repurchase program for $191.6 million, or $16.17 per share. See Note 7, Stockholders' Equity, for additional information regarding the Company's share repurchase program.
	Equity Award Grant
	In January 2014, we granted equity incentive awards to our employees under the 2004 Plan.  The grants included 1,633,898 shares of restricted stock valued at $16.55 per share (the closing price of Denbury’s common stock on January 3, 2014). The awards generally vest 33% per year over a three-year period.
	Dividend Declaration
	On January 28, 2014, the Board of Directors declared a dividend of $0.0625 per share on our common stock, payable to stockholders of record at the close of business on February 25, 2014.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Organization and Nature of Operations	'
	Organization and Nature of Operations
	Denbury Resources Inc., a Delaware corporation, is a growing, dividend-paying, domestic oil and natural gas company.  Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary 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) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price allocations, including goodwill.  While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.
Reclassifications	'
	Reclassifications
	Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.
Cash Equivalents	'
	Cash Equivalents
	We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.
Restricted Cash	'
	Restricted Cash
	Restricted cash at December 31, 2012 consisted of proceeds from the exchange of oil and gas properties with Exxon Mobil Corporation and its wholly-owned subsidiary, XTO Energy Inc., (see Note 2, Acquisitions and Divestitures) previously held by a qualified intermediary and which were restricted for application towards future acquisitions to enable like-kind-exchange transactions for federal income tax purposes, which exchange transactions took place in 2013.
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 acquisitions, 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 Measurements and Disclosures 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.
	Ceiling Test. 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 the 12-month 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 those costs have previously been incurred by the Company.  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 have a ceiling test write-down during the years ended December 31, 2013, 2012 or 2011.
	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 SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until there is a production response to the injected CO2, 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 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.
	During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit ("Riley Ridge"), which contains helium and CO2 reserves (non-hydrocarbon resources) as well as natural gas reserves (a hydrocarbon resource).  It is not possible to separately identify the capitalized costs related to the development of each product in the commingled gas stream; thus, these costs are allocated to each product based on the relative future revenue value of each product line and classified accordingly on the Consolidated Balance Sheets.
	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 reserves is included in the ceiling test as a reduction to future net revenues.  The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.
	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 15 to 50 years.
	Pipelines and plants include the Riley Ridge gas processing facility in southwestern Wyoming. We placed the Riley Ridge gas processing facility in service in the fourth quarter of 2013. Individual components of the plant are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years.
	Property and Equipment – Other
	Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, 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.
	Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability.  Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.
	Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.
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 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 and are discounted using our credit-adjusted-risk-free rate.  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 Measurements and Disclosures 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 or collars, and fixed price swaps.  Our derivative financial instruments 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 oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized 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 cash settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our Consolidated Statements of Operations.
	From time to time, we enter 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.  We do not hold or issue derivative financial instruments for trading purposes.  These contracts have consisted of price floors, collars and fixed price swaps.  The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices.  We currently employ a strategy to hedge a portion of our forecasted production approximately 18 months to two years in the future from the current quarter, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility.
	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. As of December 31, 2013, 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.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk	'
	Financial Instruments with Off-Balance-Sheet Risk and 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 banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates.  There are no margin requirements with the counterparties of our derivative contracts.
Goodwill and Other Intangible Assets	'
	Goodwill and Other Intangible Assets
	Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units.  However, we have only one reporting unit.  To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value.  Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit.  If it is determined that the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense.  We completed our annual goodwill impairment assessment during the fourth quarter of 2013 and did not record any goodwill impairment during 2013, nor have we recorded a goodwill impairment historically.
Revenue Recognition	'
	Revenue Recognition
	Revenue Recognition. Revenue is recognized at the time oil and natural gas is produced and sold.  Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.
	We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property.  A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.  As of December 31, 2013 and 2012, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.
	We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements.  We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date.
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.
	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 stock options, stock appreciation rights ("SARs"), nonvested restricted stock and nonvested performance equity awards. For each of the three years in the period ended December 31, 2013, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.
	For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.6 million, 4.1 million and 5.0 million shares for the years ended December 31, 2013, 2012 and 2011, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.
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.
Recently Adopted Accounting Pronouncements	'
	Recent Accounting Pronouncements
	Balance Sheet-Offsetting Assets and Liabilities.  In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-11, Disclosure about Offsetting Assets and Liabilities ("ASU 2011-11").  ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013, and have been applied retrospectively for all comparative periods presented.  The adoption of ASU 2011-11 and ASU 2013-01 did not affect our consolidated financial statements, but required additional disclosures in the notes thereto.
Fair Value Measurements and Disclosures	'
	The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (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 market 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 and natural gas derivatives that are based on NYMEX pricing.  Our swap contracts are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, including 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 from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.  At December 31, 2013, instruments in this category include non-exchange-traded oil collars that are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued using the Black-Scholes model, which is described above. 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. Implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. A one percent increase or decrease in implied volatility would result in a change of approximately $0.1 million in the fair value of these instruments as of December 31, 2013.
	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.

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Changes in goodwill	'
	The following table summarizes the changes in goodwill for the years ended December 31, 2013 and 2012:
		Year Ended December 31,
	In thousands	2013			2012
	Beginning of year balance	$	1,283,590		$	1,236,318
	Goodwill related to the Thompson Field acquisition	—			47,272
	End of year balance	$	1,283,590		$	1,283,590
Schedule of Finite-Lived Intangible Assets	'
	The following table summarizes the intangible asset value and related accumulated amortization as of December 31, 2013 and 2012:
	In thousands	Helium Production Rights			CO2 Purchase Contract			Total
	31-Dec-13
	Intangible asset value	$	55,266		$	33,931		$	89,197
	Accumulated amortization	—			(1,319		)	(1,319		)
	Net book value as of December 31, 2013	$	55,266		$	32,612		$	87,878
	December 31, 2012
	Intangible asset value	$	55,266		$	33,901		$	89,167
	Accumulated amortization	—			—			—
	Net book value as of December 31, 2012	$	55,266		$	33,901		$	89,167
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	'
	At December 31, 2013, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
	In thousands
	2014	$	2,748
	2015	2,843
	2016	2,915
	2017	2,915
	2018	3,568
Weighted average shares used in basic and diluted net income per common share	'
	The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:
		Year Ended December 31,
	In thousands	2013		2012			2011
	Basic weighted average common shares	366,659		385,205			396,023
	Potentially dilutive securities:
	Restricted stock, stock options, SARs and performance-based equity awards	3,218		3,733			4,935
	Diluted weighted average common shares	369,877		388,938			400,958

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisition [Line Items]	'
Business Acquisition, Pro Forma Information	'
	Unaudited Pro Forma Acquisition Information.  The following combined pro forma total revenues and other income and net income are presented as if the previously discussed CCA acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:
			Year Ended December 31,
	In thousands, except per-share data		2013			2012
	Pro forma total revenues and other income		$	2,599,301		$	2,570,829
	Pro forma net income		437,616			582,033
	Pro forma net income per common share
	Basic		$	1.19		$	1.51
	Diluted		1.18			1.5
Cedar Creek Anticline [Member]	'
Business Acquisition [Line Items]	'
Schedule of Business Acquisitions	'
	The following table presents a summary of the fair value of assets acquired and liabilities assumed in the CCA acquisition:
	In thousands
	Consideration
	Cash consideration (1)		$	1,001,707
	Fair value of assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved properties		783,507
	Unevaluated properties		222,820
	Other assets		2,589
	Asset retirement obligations		(7,209		)
			$	1,001,707
	-1	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.
Bakken Exchange Transaction [Member]	'
Business Acquisition [Line Items]	'
Schedule of Business Acquisitions	'
	The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Bakken Exchange Transaction:
	In thousands
	Consideration
	Fair value of net assets transferred		$	1,866,107
	Less: Fair value of assets acquired and liabilities assumed
	Cash (1)		1,277,041
	Oil and natural gas properties
	Proved properties		182,289
	Unevaluated properties		90,690
	CO2 properties		314,505
	Other property and equipment		23,424
	Other assets		477
	Other liabilities		(8,528		)
	Asset retirement obligations		(13,791		)
	Fair value of net assets acquired		$	1,866,107
	-1	See Note 13, Supplemental Cash Flow Information, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust in order to enable a like-kind exchange transaction for federal income tax purposes.
Thompson Field [Member]	'
Business Acquisition [Line Items]	'
Schedule of Business Acquisitions	'
	The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson Field acquisition:
	In thousands
	Consideration
	Cash consideration (1)		$	366,179
	Less: Fair value of assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved properties		305,233
	Unevaluated properties		12,023
	Pipelines and plants		2,000
	Other assets		2,957
	Asset retirement obligations		(3,306		)
			318,907
	Goodwill		$	47,272
	-1	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Table Text Block Supplement [Abstract]	'
Changes In Asset Retirement Obligations	'
	The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2013 and 2012:
			Year Ended December 31,
	In thousands		2013			2012
	Beginning asset retirement obligation		$	106,430		$	93,468
	Liabilities incurred and assumed during period		22,216			50,956
	Revisions in estimated retirement obligations		4,730			5,334
	Liabilities settled and sold during period		(15,523		)	(50,556		)
	Accretion expense		8,448			7,228
	Ending asset retirement obligation		126,301			106,430
	Less: current asset retirement obligation (1)		(6,413		)	(3,700		)
	Long-term asset retirement obligation		$	119,888		$	102,730
	-1	Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Summary of net property and equipment balances	'
	The following table presents a summary of our net property and equipment balances as of December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Oil and natural gas properties
	Proved properties		$	8,945,326		$	6,963,211
	Unevaluated properties		780,481			809,154
	Total		9,725,807			7,772,365
	Accumulated depletion and depreciation		(3,219,500		)	(2,827,256		)
	Net oil and natural gas properties		6,506,307			4,945,109
	CO2 properties
	CO2 properties		1,117,167			1,032,653
	Accumulated depletion and depreciation		(150,968		)	(119,784		)
	Net CO2 properties		966,199			912,869
	Pipelines and plants
	CO2 pipelines (1)		1,681,774			1,632,255
	Plants		527,786			402,871
	Total		2,209,560			2,035,126
	Accumulated depletion and depreciation		(134,697		)	(99,185		)
	Net plants and pipelines		2,074,863			1,935,941
	Other property and equipment
	Other property and equipment		466,969			417,207
	Accumulated depletion and depreciation		(163,060		)	(134,016		)
	Net other property and equipment		303,909			283,191
	Net property and equipment		$	9,851,278		$	8,077,110
	-1	Amounts include $48.4 million of CO2 pipelines at December 31, 2013 that were under construction and not subject to depreciation during 2013.
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, 2013, and the year in which the costs were incurred follows:
			December 31, 2013
			Costs Incurred During:
	In thousands		2013			2012			2011		2010 and prior		Total
	Property acquisition costs		$	215,822		$	109,275		$	12,543	$	317,226	$	654,866
	Exploration and development		41,157			22,080			7,408		10,825		81,470
	Capitalized interest		25,222			12,084			6,018		821		44,145
	Total		$	282,201		$	143,439		$	25,969	$	328,872	$	780,481

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Components of Long-Term Debt	'
	The following long-term debt and capital lease obligations were outstanding as of December 31, 2013 and 2012:
		December 31,
	In thousands	2013			2012
	Bank Credit Agreement	$	340,000		$	700,000
	9½% Senior Subordinated Notes due 2016, including premium of $9,118	—			234,038
	9¾% Senior Subordinated Notes due 2016, including discount of $13,569	—			412,781
	8¼% Senior Subordinated Notes due 2020	996,273			996,273
	6 3/8% Senior Subordinated Notes due 2021	400,000			400,000
	4 5/8% Senior Subordinated Notes due 2023	1,200,000			—
	Other Subordinated Notes, including premium of $16 and $25, respectively	3,823			3,832
	Pipeline financings	228,167			236,244
	Capital lease obligations	128,519			158,260
	Total	3,296,782			3,141,428
	Less: current obligations	(36,157		)	(36,966		)
	Long-term debt and capital lease obligations	$	3,260,625		$	3,104,462
Indebtedness repayable over the next five years and thereafter	'
	At December 31, 2013, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
	In thousands
	2014	$	36,156
	2015	37,634
	2016	377,933
	2017	36,855
	2018	31,899
	Thereafter	2,776,288
	Total indebtedness	$	3,296,765

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Provision (Benefit)	'
	Our income tax provision (benefit) is as follows:
		Year Ended December 31,
	In thousands	2013			2012			2011
	Current income tax expense (benefit)
	Federal	$	393		$	57,720		$	(12,552	)
	State	9,864			18,034			20,801
	Total current income tax expense	10,257			75,754			8,249
	Deferred income tax expense (benefit)
	Federal	222,559			239,862			329,715
	State	(33		)	15,881			12,748
	Total deferred income tax expense	222,526			255,743			342,463
	Total income tax expense	$	232,783		$	331,497		$	350,712
Deferred Tax Assets And Liabilities	'
	Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
		December 31,
	In thousands	2013			2012
	Deferred tax assets
	Loss carryforwards – federal	$	20,247		$	—
	Loss carryforwards – state	41,379			35,007
	Tax credit carryover	34,837			34,837
	Derivative contracts	21,341			7,252
	Enhanced oil recovery credit carryforwards	14,974			17,346
	Stock-based compensation	34,635			28,387
	Other	37,679			37,226
	Total deferred tax assets	205,092			160,055
	Deferred tax liabilities
	Property and equipment	(2,541,426		)	(2,277,388		)
	Other	(10,206		)	(6,963		)
	Total deferred tax liabilities	(2,551,632		)	(2,284,351		)
	Total net deferred tax liability	$	(2,346,540	)	$	(2,124,296	)
Income Tax Provision (Benefit) Continuing Operations Income Tax 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	2013			2012			2011
	Income tax provision calculated using the federal statutory income tax rate	$	224,833		$	299,900		$	323,416
	State income taxes, net of federal income tax benefit	13,518			30,955			29,555
	Effect of statutory rate change	(4,178		)	(429		)	(578		)
	Other	(1,390		)	1,071			(1,681		)
	Total income tax expense	$	232,783		$	331,497		$	350,712

Stockholders_Equity_Tables

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Summary of Share Repurchases Table	'
	The following table presents a summary of repurchases under our share repurchase program:
		Total repurchases since inception		Year Ended December 31,
	Dollar amounts in thousands, except per-share data			2013		2012		2011
	Total amount repurchased	$	739,652	$	277,768	$	266,657	$	195,227
	Weighted average price per share	$	15.55	$	16.87	$	15.71	$	13.83
	Denbury common stock repurchased (shares)	47,559,266		16,468,648		16,978,008		14,112,610

Stock_Compensation_Plans_Table

Stock Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Stock Compensation Plans [Line Items]	'
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	'
	Stock-based compensation costs for the years ended December 31, 2013, 2012 and 2011, are as follows:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Stock-based compensation expensed:
	General and administrative expenses		$	30,429			$	26,463			$	30,256
	Lease operating expenses		2,574				2,847				2,621
	Other expenses		—				—				313
	Total stock-based compensation expensed		33,003				29,310				33,190
	Stock-based compensation capitalized		9,088				8,587				6,998
	Total cost of stock-based compensation arrangements		$	42,091			$	37,897			$	40,188
	Income tax benefit recognized for stock-based compensation arrangements		$	12,541			$	11,284			$	12,612
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	'
			2013				2012				2011
	Weighted average fair value of SARs granted		$	6.72			$	8.9			$	9.68
	Risk-free interest rate		0.67		%		0.79		%		1.74		%
	Expected life		3.6 to 4.8 years				4.0 to 5.0 years				4.0 to 5.0 years
	Expected volatility		50.4		%		64.9		%		63.3		%
	Dividend yield		—		%		—		%		—		%
Summary of stock option and SARs activity	'
	The following is a summary of our stock option and SAR activity:
			Number			Weighted				Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
			of Awards			Average				(in years)		(in thousands)
						Exercise Price
	Outstanding at December 31, 2012		10,445,135			$	14.75
	Granted		720,859			16.95
	Exercised		(1,970,426	)		9.33
	Forfeited		(113,509	)		17.31
	Expired		(95,144	)		22.74
	Outstanding at December 31, 2013		8,986,915			16				3.3		$	19,319
	Exercisable at end of period		6,632,141			$	15.51			2.7		$	18,970
Disclosure of intrinsic value of stock options exercised and grant-date fair value of awards vested	'
	The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair value of stock options and SARs vested:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Intrinsic value of stock options exercised		$	17,287			$	17,315			$	20,463
	Grant-date fair value of stock options and SARs vested		12,852				26,391				11,416
Schedule of Cash Proceeds Received from Share-based Payment Awards	'
	The following is a summary of cash received from stock option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock options and SARs:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Cash received from stock option exercises		$	5,487			$	6,022			$	4,685
	Tax benefit realized for the exercises of stock options and SARs		437				458				539
Performance equity awards [Member]	'
Stock Compensation Plans [Line Items]	'
Schedule of Nonvested Performance-based Units Activity	'
	A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2013 is as follows:
			Performance-Based							Performance-Based
			Operational Awards							TSR Awards
			Number			Weighted				Number			Weighted
			of Awards			Average				of Awards			Average
						Grant-Date Fair Value							Grant-Date Fair Value
	Nonvested at December 31, 2012		100,193			$	17.27			86,917			$	24.68
	Granted		215,258			16.77				209,474			20.08
	Vested (1)		(100,193	)		17.27				—			—
	Forfeited		(5,784	)		16.77				—			—
	Nonvested at December 31, 2013		209,474			16.77				296,391			21.43
	-1	During 2013, the 2012 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 136% of the number of target-level shares.
Performance-based TSR Awards [Member]	'
Stock Compensation Plans [Line Items]	'
Summary of Share-Based Award Valuation Assumptions	'
	The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:
			Year Ended December 31,
			2013				2012
	Weighted average fair value of Performance-based TSR Award granted		$	20.08			$	24.68
	Risk-free interest rate		0.41		%		0.42		%
	Expected life		3.0 years				2.8 years
	Expected volatility		42.3		%		45.2		%
	Dividend yield		—		%		—		%
Performance-based Operational Award [Member]	'
Stock Compensation Plans [Line Items]	'
Summary of Vesting Date Fair Value Of Awards	'
	The following is a summary of the total vesting date fair value of performance-based equity awards:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Vesting date fair value of Performance-based Operational Awards		$	2,541			$	2,191			$	10,892
2004 Omnibus Stock and Incentive Plan | Restricted Stock [Member]	'
Stock Compensation Plans [Line Items]	'
Summary of Vesting Date Fair Value Of Awards	'
	The following is a summary of the total vesting date fair value of restricted stock under the 2004 Plan:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Fair value of restricted stock vested		$	21,529			$	22,332			$	12,355
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	'
	A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes during the year ended December 31, 2013 is presented below:
			Number			Weighted
			of Shares			Average
						Grant-Date
						Fair Value
	Nonvested at December 31, 2012		3,406,207			$	15.6
	Granted		1,805,467			16.96
	Vested		(1,310,347	)		16.21
	Forfeited		(165,917	)		17.23
	Nonvested at December 31, 2013		3,735,410			15.97
Encore Plan [Member] | Restricted Stock [Member]	'
Stock Compensation Plans [Line Items]	'
Summary of Vesting Date Fair Value Of Awards	'
	The following is a summary of the total vesting date fair value of restricted stock under the Encore Plan:
			Year Ended December 31,
	In thousands		2013				2012				2011
	Fair value of restricted stock vested		$	512			$	584			$	2,259
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	'
	A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2013 is presented below:
			Number			Weighted
			of Shares			Average
						Grant-Date
						Fair Value
	Nonvested at December 31, 2012		56,258			$	15.43
	Vested		(31,140	)		15.43
	Forfeited		(3,377	)		15.43
	Nonvested at December 31, 2013		21,741			15.43

Commodity_Derivative_Contracts1

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity derivative contracts not classified as hedging instruments	'
	The following table summarizes our commodity derivative contracts, none of which are classified as hedging instruments:
	Year		Months	Type of Contract	Pricing Index	Volume (2)	Contract Prices (1)
							Range				Weighted Average Price
											Swap		Floor		Ceiling
	Oil Contracts:
	2014		Jan – Mar	Swap	NYMEX	58,000	$	91.67	–	95.95	$	93.53	$	—	$	—
			Apr – June	Swap	NYMEX	58,000		91.67	–	95.95	93.53		—		—
			July – Sept	Swap	NYMEX	58,000		90	–	93.5	92.52		—		—
			Oct – Dec	Swap	NYMEX	58,000		90	–	93.5	92.52		—		—
	2015		Jan – Mar	Collar	NYMEX	38,000	$	80	–	100.9	$	—	$	80	$	96.96
			Jan – Mar	Collar	LLS	20,000		85	–	104	—		85		101.45
			Apr – June	Collar	NYMEX	38,000		80	–	95.25	—		80		94.62
			Apr – June	Collar	LLS	20,000		85	–	103	—		85		102.01
			July – Sept	Collar	NYMEX	38,000		80	–	95.25	—		80		95.04
			July – Sept	Collar	LLS	20,000		85	–	102.6	—		85		100.69
	Natural Gas Contracts:
	2014		Jan – Dec	Collar	NYMEX	14,000	$	4	–	4.47	$	—	$	4	$	4.45
	-1	Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
	-2	Contract volumes are stated in Bbl/d and MMBtu/d for oil and natural gas contracts, respectively.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012:
		Fair Value Measurements Using:
		Quoted Prices		Significant			Significant
		in Active		Other			Unobservable
		Markets		Observable			Inputs
				Inputs
	In thousands	(Level 1)		(Level 2)			(Level 3)			Total
	December 31, 2013
	Assets:
	Oil and natural gas derivative contracts – current	$	—	$	5		$	—		$	5
	Oil and natural gas derivative contracts – long-term	—		3,034			6,908			9,942
	Total Assets	$	—	$	3,039		$	6,908		$	9,947
	Liabilities:
	Oil and natural gas derivative contracts – current	$	—	$	(53,822	)	$	—		$	(53,822	)
	Oil and natural gas derivative contracts – long-term	—		(3,214		)	(199		)	(3,413		)
	Total Liabilities	$	—	$	(57,036	)	$	(199	)	$	(57,235	)
	December 31, 2012
	Assets:
	Oil and natural gas derivative contracts – current	$	—	$	19,477		$	—		$	19,477
	Oil and natural gas derivative contracts – long-term	—		36			—			36
	Total Assets	$	—	$	19,513		$	—		$	19,513
	Liabilities:
	Oil and natural gas derivative contracts – current	$	—	$	(2,659	)	$	—		$	(2,659	)
	Oil and natural gas derivative contracts – long-term	—		(23,781		)	—			(23,781		)
	Total Liabilities	$	—	$	(26,440	)	$	—		$	(26,440	)
The changes in the fair value of Denbury's Level 3 assets and liabilities for the twelve months ended	'
	The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2013 and 2012:
		Year Ended December 31,
	In thousands	2013		2012
	Fair value of Level 3 instruments, beginning of year	$	—	$	23,950
	Fair value adjustments on commodity derivatives	6,709		3,921
	Receipt on settlements of commodity derivatives	—		(27,871		)
	Fair value of Level 3 instruments, end of year	$	6,709	$	—
	The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date	$	6,709	$	—

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Table Text Block [Abstract]	'
Schedule of operating lease payments paid and received	'
	The following table summarizes operating lease payments paid and received during the periods indicated:
		Year Ended December 31,
	In thousands	2013			2012		2011
	Operating lease payments	$	37,211		$	33,606	$	52,317
	Sublease rental receipts	2,237			2,685		2,398
Schedule of capital long-term commitments which require future minimum rental payments	'
	The following table summarizes by year the remaining non-cancelable future payments under these leases as of December 31, 2013:
	In thousands	Pipeline
		and Capital Leases
	2014	$	62,929
	2015	62,254
	2016	60,819
	2017	55,409
	2018	50,750
	Thereafter	280,272
	Total minimum lease payments	572,433
	Less: Amount representing interest	(215,748		)
	Present value of minimum lease payments	$	356,685
Schedule of operating long-term commitments which require future minimum lease payments	'
	In thousands	Operating
		Leases
	2014	$	11,695
	2015	12,542
	2016	12,510
	2017	12,774
	2018	12,730
	Thereafter	67,832
	Total minimum lease payments	$	130,083

Additional_Balance_Sheet_Detai1

Additional Balance Sheet Details (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Accounts Payable and Accrued Liabilities	'
	Accounts Payable and Accrued Liabilities
		December 31,
	In thousands	2013		2012
	Accrued exploration and development costs	$	100,564	$	109,939
	Accrued interest	68,871		60,698
	Accounts payable	63,263		86,051
	Accrued lease operating expenses	59,762		23,862
	Accrued compensation	55,043		48,451
	Taxes payable	28,019		27,523
	Other	35,021		58,144
	Total	$	410,543	$	414,668

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Schedule of Cash Flow, Supplemental Disclosure	'
	Supplemental Cash Flow Information
			Year Ended December 31,
	In thousands		2013			2012			2011
	Supplemental cash flow information:
	Cash paid for interest, expensed		$	117,442		$	137,950		$	137,259
	Cash paid for interest, capitalized		79,253			77,432			60,540
	Cash paid for income taxes		28,895			99,194			45,912
	Cash received from income tax refunds		(17,087		)	(38,004		)	(24,677		)
	Noncash investing activities:
	Increase in asset retirement obligations		26,946			56,290			24,694
	Increase (decrease) in liabilities for capital expenditures		(18,321		)	(26,882		)	74,697
	Increase in restricted cash (1)		—			1,262,559			—
	Decrease in restricted cash (2)		1,050,328			212,544			—
	-1	During 2012, $212.5 million of proceeds from the sale of certain non-core assets in the Gulf Coast Region and $1.05 billion of the cash proceeds from the Bakken Exchange Transaction were paid by the respective purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.
	-2	During 2012 and 2013, proceeds from the sales of our oil and natural gas property dispositions in 2012, which were held by a qualified intermediary, were released in 2012 to fund the Thompson Field acquisition and in 2013 primarily to fund a portion of the CCA acquisition and certain post-closing costs under the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.

Significant_Accounting_Policie3

Significant Accounting Policies (Goodwill Rollforward) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Changes in goodwill	'	'
Beginning of year balance	$1,283,590	$1,236,318
Goodwill related to the Thompson Field acquisition	0	47,272
End of year balance	$1,283,590	$1,283,590

Significant_Accounting_Policie4

Significant Accounting Policies (Intangibles) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'	'
Intangible asset value	$89,197	$89,167
Accumulated amortization	-1,319	0
Net book value	87,878	89,167
Helium Production Rights [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Intangible asset value	55,266	55,266
Accumulated amortization	0	0
Net book value	55,266	55,266
CO2 Purchase Contract [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Intangible asset value	33,931	33,901
Accumulated amortization	-1,319	0
Net book value	$32,612	$33,901

Significant_Accounting_Policie5

Significant Accounting Policies (Estimated Amortization Expense for Intangibles) (Details 1) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]	'
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	$2,748
Finite-Lived Intangible Assets, Amortization Expense, Year Two	2,843
Finite-Lived Intangible Assets, Amortization Expense, Year Three	2,915
Finite-Lived Intangible Assets, Amortization Expense, Year Four	2,915
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$3,568

Significant_Accounting_Policie6

Significant Accounting Policies (Reconciliation of Weighted Average Shares Table) (Details 2)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Weighted average shares used in the basic and diluted net income per common share	'	'	'
Basic weighted average common shares	366,659	385,205	396,023
Potentially dilutive securities:	'	'	'
Restricted stock, stock options, SARs and performance-based equity awards	3,218	3,733	4,935
Diluted weighted average common shares	369,877	388,938	400,958

Significant_Accounting_Policie7

Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
Share data in Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Accounting Policies [Line Items]	'	'	'
Ceiling test write-down	$0	$0	$0
Impairment of Goodwill	0	0	0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	3.6	4.1	5
Amortization of Intangible Assets	$1,300,000	'	'
Minimum [Member] | Co2 Property And Pipelines [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'15 years	'	'
Minimum [Member] | Riley Ridge gas processing facility [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'20 years	'	'
Minimum [Member] | Vehicles and furniture and fixtures [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'5 years	'	'
Minimum [Member] | Computer equipment and software [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'3 years	'	'
Maximum [Member] | Co2 Property And Pipelines [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'50 years	'	'
Maximum [Member] | Riley Ridge gas processing facility [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'50 years	'	'
Maximum [Member] | Vehicles and furniture and fixtures [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'10 years	'	'
Maximum [Member] | Computer equipment and software [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'5 years	'	'

Significant_Accounting_Policie8

Significant Accounting Policies (Major Customers) (Details Textuals 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Rate	Rate	Rate
Marathon Petroleum Company [Member]	'	'	'
Product Information [Line Items]	'	'	'
Revenue from major customer (percentage)	33.00%	39.00%	43.00%
Plains Marketing LP [Member]	'	'	'
Product Information [Line Items]	'	'	'
Revenue from major customer (percentage)	15.00%	17.00%	16.00%
Eighty-Eight Oil LLC [Member]	'	'	'
Product Information [Line Items]	'	'	'
Revenue from major customer (percentage)	10.00%	'	'

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (CCA PPA) (Details) (Cedar Creek Anticline [Member], USD $)	0 Months Ended
In Thousands, unless otherwise specified	Mar. 27, 2013
Cedar Creek Anticline [Member]	'
Business Acquisition [Line Items]	'
Cash consideration	$1,001,707	[1]
Proved properties	783,507
Unevaluated properties	222,820
Other assets	2,589
Asset retirement obligations	-7,209
Fair value of net assets acquired	$1,001,707
[1]	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures (Bakken Exchange Transaction PPA) (Details1) (USD $)	3 Months Ended
	Dec. 31, 2012
Business Acquisition [Line Items]	'
Restricted cash	$1,050,000,000
Bakken Exchange Transaction [Member]	'
Business Acquisition [Line Items]	'
Fair value of net assets transferred	1,866,107,000
Cash	1,277,041,000	[1]
Proved properties	182,289,000
Unevaluated properties	90,690,000
CO2 properties	314,505,000
Other property and equipment	23,424,000
Other assets	477,000
Other liabilities	-8,528,000
Asset retirement obligations	-13,791,000
Fair value of net assets acquired	$1,866,107,000
[1]	See Note 13, Supplemental Cash Flow Information, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust in order to enable a like-kind exchange transaction for federal income tax purposes.

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures (Thompson Field PPA) (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012
In Thousands, unless otherwise specified				Thompson Field [Member]
Business Acquisition [Line Items]	'	'	'	'
Cash consideration	'	'	'	$366,179	[1]
Proved properties	'	'	'	305,233
Unevaluated properties	'	'	'	12,023
Pipelines and plants	'	'	'	2,000
Other assets	'	'	'	2,957
Asset retirement obligations	'	'	'	-3,306
Fair value of net assets acquired	'	'	'	318,907
Goodwill	$1,283,590	$1,283,590	$1,236,318	$47,272
[1]	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures (Pro Forma Table Thompson and Bakken) (Details 3) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]	'	'
Pro forma total revenues and other income	$2,599,301	$2,570,829
Pro forma net income	$437,616	$582,033
Pro forma net income per common share	'	'
Basic	$1.19	$1.51
Diluted	$1.18	$1.50

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures (Details Textuals) (USD $)

12 Months Ended

0 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 27, 2013

Dec. 31, 2013

Jan. 31, 2013

Dec. 31, 2012

Jun. 30, 2012

Apr. 30, 2012

Dec. 31, 2012

Feb. 29, 2012

Dec. 31, 2012

Cedar Creek Anticline [Member]

Cedar Creek Anticline [Member]

Cedar Creek Anticline [Member]

Bakken Exchange Transaction [Member]

Thompson Field [Member]

Paradox Basin [Member]

Paradox Basin [Member]

Non-core Gulf Coast Assets [Member]

Non-core Gulf Coast Assets [Member]

Scenario, Plan [Member]

Rate

Rate

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Businesses, Gross

'

'

'

$1,001,707,000

[1]

'

$1,050,000,000

'

$366,179,000

[1]

'

'

'

'

Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual

'

'

'

'

268,300,000

'

'

'

'

'

'

'

Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual

'

'

'

'

194,200,000

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents

'

'

'

'

'

'

1,277,041,000

[2]

'

'

'

'

'

Percent of Overriding Royalty Interest in CO2 Properties Acquired in a Business Acquisition

'

'

'

'

'

'

33.33%

'

'

'

'

'

Net working interest acquired in purchase of oil and natural gas properties

'

'

'

'

'

'

'

100.00%

'

'

'

'

Net revenue interest acquired in purchase of oil and natural gas properties

'

'

'

'

'

'

'

84.70%

'

'

'

'

Net Revenue Interest Retained By Seller

'

'

'

'

'

'

'

5.00%

'

'

'

'

Oil Production Threshold (in Bbls/d)

'

'

'

'

'

'

'

3,000

'

'

'

'

Proceeds from sale of oil and natural gas properties and equipment

8,037,000

34,750,000

69,370,000

'

'

'

'

'

68,500,000

'

141,800,000

'

Gain (Loss) on Sale of Property

'

'

'

'

'

'

'

'

'

$0

'

$0

[1]

See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13, Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.

[2]

See Note 13, Supplemental Cash Flow Information, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust in order to enable a like-kind exchange transaction for federal income tax purposes.

Asset_Retirement_Obligations_R

Asset Retirement Obligations (Rollforward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]	'		'
Beginning asset retirement obligation	$106,430,000		$93,468,000
Liabilities incurred and assumed during period	22,216,000		50,956,000
Revisions in estimated retirement obligations	4,730,000		5,334,000
Liabilities settled and sold during period	-15,523,000		-50,556,000
Accretion expense	8,448,000		7,228,000
Ending asset retirement obligation	126,301,000		106,430,000
Asset retirement obligations - current	-6,413,000	[1]	-3,700,000	[1]
Long-term asset retirement obligation	119,888,000		102,730,000
Asset Retirement Obligations (Textuals) [Abstract]	'		'
Balances in escrow accounts	$36,000,000		$35,200,000
[1]	Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.

Property_and_Equipment_Summary

Property and Equipment (Summary of Net Property and Equipment) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Property, Plant and Equipment [Abstract]	'		'
Proved properties	$8,945,326,000		$6,963,211,000
Unevaluated properties	780,481,000		809,154,000
Total	9,725,807,000		7,772,365,000
Accumulated depletion and depreciation of oil and natural gas properties	-3,219,500,000		-2,827,256,000
Net oil and natural gas properties	6,506,307,000		4,945,109,000
CO2 properties	1,117,167,000		1,032,653,000
CO2 pipelines	1,681,774,000	[1]	1,632,255,000
Plants	527,786,000		402,871,000
Total	2,209,560,000		2,035,126,000
Other property and equipment	466,969,000		417,207,000
Property, Plant and Equipment [Line Items]	'		'
Accumulated depletion and depreciation	-3,668,225,000		-3,180,241,000
Net property and equipment	9,851,278,000		8,077,110,000
CO2 pipelines not placed in service	48,400,000		'
CO2 properties [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Accumulated depletion and depreciation	-150,968,000		-119,784,000
Net property and equipment	966,199,000		912,869,000
Pipelines and plants [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Accumulated depletion and depreciation	-134,697,000		-99,185,000
Net property and equipment	2,074,863,000		1,935,941,000
Other property and equipment [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Accumulated depletion and depreciation	-163,060,000		-134,016,000
Net property and equipment	$303,909,000		$283,191,000
[1]	Amounts include $48.4 million of CO2 pipelines at December 31, 2013 that were under construction and not subject to depreciation during 2013.

Property_and_Equipment_Summary1

Property and Equipment (Summary of Unevaluated Properties Excluded from Amortization) (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of unevaluated properties excluded from oil and natural gas properties being amortized	'	'	'	'
Property acquisition costs	$215,822	$109,275	$12,543	$317,226
Exploration and development	41,157	22,080	7,408	10,825
Capitalized interest	25,222	12,084	6,018	821
Total	282,201	143,439	25,969	328,872
Property acquisition costs	654,866	'	'	'
Exploration and development	81,470	'	'	'
Capitalized interest	44,145	'	'	'
Total	$780,481	$809,154	'	'

Property_and_Equipment_Details

Property and Equipment (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'
Cost Incurred On Proved Reserves Transferred To Amortization Base	$417.60
Minimum [Member]	'
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'
Anticipated Timing of Inclusion of Costs in Amortization Calculation	'5 years
Maximum [Member]	'
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'
Anticipated Timing of Inclusion of Costs in Amortization Calculation	'10 years

LongTerm_Debt_Components_of_Lo

Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)	Dec. 31, 2013	Jan. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'	'
Bank Credit Agreement	$340,000	'	$700,000
Pipeline financings	228,167	'	236,244
Capital lease obligations	128,519	'	158,260
Total	3,296,782	'	3,141,428
Less: current obligations	-36,157	'	-36,966
Long-term debt and capital lease obligations	3,260,625	'	3,104,462
9 1/2% Senior Subordinated Notes due 2016 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	0	224,900	234,038
Including premium of	0	'	9,118
Debt Instrument, Interest Rate, Stated Percentage	9.50%	'	'
9 3/4% Senior Subordinated Notes due 2016 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	0	426,400	412,781
Including discount of	0	'	13,569
Debt Instrument, Interest Rate, Stated Percentage	9.75%	'	'
8 1/4% Senior Subordinated Notes due 2020 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	996,273	'	996,273
Debt Instrument, Interest Rate, Stated Percentage	8.25%	'	'
6 3/8% Senior Subordinated Notes due 2021 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	400,000	'	400,000
Debt Instrument, Interest Rate, Stated Percentage	6.38%	'	'
4 5/8% Senior Subordinated Notes due 2023 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	1,200,000	'	0
Debt Instrument, Interest Rate, Stated Percentage	4.63%	'	'
Other Subordinated Notes [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior subordinated notes	3,823	'	3,832
Including premium of	$16	'	$25

LongTerm_Debt_Debt_Maturity_Sc

Long-Term Debt (Debt Maturity Schedule) (Details 1) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Indebtedness repayment schedule	'
2014	$36,156
2015	37,634
2016	377,933
2017	36,855
2018	31,899
Thereafter	2,776,288
Total indebtedness	$3,296,765

LongTerm_Debt_Details_Textuals

Long-Term Debt (Details Textuals) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Feb. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Nov. 01, 2013

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2011

31-May-13

Feb. 28, 2013

Dec. 31, 2013

Jan. 31, 2013

Dec. 31, 2012

Mar. 31, 2013

Feb. 28, 2013

Dec. 31, 2013

Jan. 31, 2013

Dec. 31, 2012

Feb. 28, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Feb. 28, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Feb. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Rate

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

7 1/2% Senior Subordinated Notes due 2013 [Member]

7 1/2% Senior Subordinated Notes due 2015 [Member]

9 1/2% Senior Subordinated Notes due 2016 [Member]

9 1/2% Senior Subordinated Notes due 2016 [Member]

9 1/2% Senior Subordinated Notes due 2016 [Member]

9 1/2% Senior Subordinated Notes due 2016 [Member]

9 1/2% Senior Subordinated Notes due 2016 [Member]

9 3/4% Senior Subordinated Notes due 2016 [Member]

9 3/4% Senior Subordinated Notes due 2016 [Member]

9 3/4% Senior Subordinated Notes due 2016 [Member]

9 3/4% Senior Subordinated Notes due 2016 [Member]

9 3/4% Senior Subordinated Notes due 2016 [Member]

8 1/4% Senior Subordinated Notes due 2020 [Member]

8 1/4% Senior Subordinated Notes due 2020 [Member]

8 1/4% Senior Subordinated Notes due 2020 [Member]

8 1/4% Senior Subordinated Notes due 2020 [Member]

8 1/4% Senior Subordinated Notes due 2020 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

6 3/8% Senior Subordinated Notes due 2021 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

4 5/8% Senior Subordinated Notes due 2023 [Member]

Minimum [Member]

Maximum [Member]

Eurodollar Rate [Member]

Eurodollar Rate [Member]

Base Rate [Member]

Base Rate [Member]

Base Rate Option 2 [Member]

Base Rate Option 3 [Member]

Rate

Rate

Rate

Rate

Rate

Debt Instrument, Redemption, Period One [Member]

Initial Redemption Period with Make-Whole Premium [Member]

Debt Instrument, Redemption, Period One [Member]

Initial Redemption Period with Proceeds from Equity Offering [Member]

Initial Redemption Period with Make-Whole Premium [Member]

Debt Instrument, Redemption, Period One [Member]

Initial Redemption Period with Proceeds from Equity Offering [Member]

Initial Redemption Period with Make-Whole Premium [Member]

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Rate

Rate

Rate

Rate

Rate

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Bank Credit Agreement [Member]

Rate

Rate

Rate

Rate

Rate

Rate

$1.6 Billion Revolving Credit Agreement [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing base of Bank Credit Agreement

'

'

'

'

'

$1,600,000,000

$1,600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Interest Rate During Period

'

'

'

'

1.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current Ratio Requirement

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Debt to EBITDA Requirement

'

'

'

'

4.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate margins on Bank Credit Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

2.50%

0.50%

1.50%

0.50%

1.00%

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

Minimum Bank Credit Facility Availability Percentage To Pay Dividends

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

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'

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'

'

'

'

'

'

Debt Instruments [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

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'

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'

'

'

'

'

'

'

'

'

'

'

Subordinated Debt

'

'

'

'

'

'

'

'

'

'

'

0

224,900,000

234,038,000

'

'

0

426,400,000

412,781,000

'

996,273,000

996,273,000

'

'

'

400,000,000

400,000,000

'

'

'

'

1,200,000,000

0

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage

'

'

'

'

'

'

'

'

'

104.75%

106.87%

'

'

'

104.88%

105.43%

'

'

'

'

'

'

104.13%

100.00%

'

'

'

103.19%

106.38%

100.00%

'

'

'

102.31%

104.63%

100.00%

'

'

'

'

'

'

'

'

Debt Instrument, Percentage of Principal Amount Available To Be Redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

225,000,000

300,000,000

38,200,000

186,700,000

'

'

'

234,700,000

191,700,000

'

'

'

3,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on early extinguishment of debt

'

44,651,000

0

16,131,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Face value of senior subordinated notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

'

'

'

'

400,000,000

'

'

'

'

'

1,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from issuance of subordinated long-term debt, net of commissions and fees

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

980,000,000

'

'

'

'

393,000,000

'

'

'

'

'

1,180,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate on senior subordinated notes

'

'

'

'

'

'

'

'

'

'

'

9.50%

'

'

'

'

9.75%

'

'

'

8.25%

'

'

'

'

6.38%

'

'

'

'

'

4.63%

'

'

'

'

'

'

'

'

'

'

'

'

Selling Price Of Debt Instrument

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

100.00%

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

Interest in guarantor subsidiaries

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease period included in long term transportation service agreement

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized debt issuance costs

'

$58,900,000

$56,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income_Taxes_Income_Tax_Provis

Income Taxes (Income Tax Provision (Benefit)) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current income tax expense (benefit)	'	'	'
Federal	$393	$57,720	($12,552)
State	9,864	18,034	20,801
Total current income tax expense	10,257	75,754	8,249
Deferred income tax expense (benefit)	'	'	'
Federal	222,559	239,862	329,715
State	-33	15,881	12,748
Total deferred income tax expense	222,526	255,743	342,463
Total income tax expense	$232,783	$331,497	$350,712

Income_Taxes_Components_of_Def

Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets	'	'
Loss carryforwards - federal	$20,247	$0
Loss carryforwards - state	41,379	35,007
Tax credit carryover	34,837	34,837
Derivative contracts	21,341	7,252
Enhanced oil recovery credit carryforwards	14,974	17,346
Stock-based compensation	34,635	28,387
Other	37,679	37,226
Total deferred tax assets	205,092	160,055
Deferred tax liabilities	'	'
Property and equipment	-2,541,426	-2,277,388
Other	-10,206	-6,963
Total deferred tax liabilities	-2,551,632	-2,284,351
Total net deferred tax liability	($2,346,540)	($2,124,296)

Income_Taxes_Schedule_of_Effec

Income Taxes (Schedule of Effective Tax Rate Reconciliation) (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate Reconciliation, Amount [Abstract]	'	'	'
Income tax provision calculated using the federal statutory income tax rate	$224,833	$299,900	$323,416
State income taxes, net of federal income tax benefit	13,518	30,955	29,555
Effect of statutory rate change	-4,178	-429	-578
Other	-1,390	1,071	-1,681
Total income tax expense	$232,783	$331,497	$350,712

Income_Taxes_Details_Textuals

Income Taxes (Details Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Loss carryforwards - federal	$20,247,000	$0
Loss carryforwards - state	41,379,000	35,007,000
Enhanced oil recovery credit carryforwards	14,974,000	17,346,000
Tax credit carryover	34,837,000	34,837,000
Tax benefit not recorded to additional paid-in capital	13,000,000	'
Valuation Allowance, Amount	$0	'

Stockholders_Equity_Share_Repu

Stockholders' Equity (Share Repurchases Textuals) (Details) (USD $)	0 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Oct. 31, 2011
Stockholders' Equity Note [Abstract]	'	'
Stock Repurchase Program, Authorized Amount	$1,162	$500
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$422.30	'

Stockholders_Equity_Share_Repu1

Stockholders' Equity (Share Repurchases Table) (Details1) (USD $)	12 Months Ended			27 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Equity, Class of Treasury Stock [Line Items]	'	'	'	'
Total amount repurchased	$277,768	$266,657	$195,227	$739,652
Weighted average price per share	$16.87	$15.71	$13.83	$15.55
Denbury common stock repurchased (shares)	16,468,648	16,978,008	14,112,610	47,559,266

Stockholders_Equity_Details_Te

Stockholders' Equity (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Benefit Plans Disclosures [Line Items]	'	'	'
Total compensation expense	$33,003,000	$29,310,000	$33,190,000
Employee Stock Purchase Plan [Member]	'	'	'
Defined Contribution Benefit Plans Disclosures [Line Items]	'	'	'
Maximum number of common stock shares authorized for issuance under Plan	11,900,000	'	'
Shares available for future awards	1,601,230	'	'
Employer contribution rate	75.00%	'	'
Total compensation expense	6,500,000	5,700,000	4,800,000
401(k) Plan [Member]	'	'	'
Defined Contribution Benefit Plans Disclosures [Line Items]	'	'	'
Employer contribution rate	100.00%	'	'
Employer's matching contributions	$9,000,000	$8,000,000	$7,100,000
Maximum [Member] | Employee Stock Purchase Plan [Member]	'	'	'
Defined Contribution Benefit Plans Disclosures [Line Items]	'	'	'
Employee contribution rate	10.00%	'	'
Maximum [Member] | 401(k) Plan [Member]	'	'	'
Defined Contribution Benefit Plans Disclosures [Line Items]	'	'	'
Employee contribution rate	6.00%	'	'

Stock_Compensation_Plans_Sched

Stock Compensation Plans (Schedule of Share-Based Compensation) (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Total stock-based compensation expensed	$33,003	$29,310	$33,190
Stock-based compensation capitalized	9,088	8,587	6,998
Total cost of stock-based compensation arrangements	42,091	37,897	40,188
Income tax benefit recognized for stock-based compensation arrangements	12,541	11,284	12,612
General and administrative expenses [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Total stock-based compensation expensed	30,429	26,463	30,256
Lease operating expenses [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Total stock-based compensation expensed	2,574	2,847	2,621
Other expenses [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Total stock-based compensation expensed	$0	$0	$313

Stock_Compensation_Plans_Summa

Stock Compensation Plans (Summary of SAR Assumptions) (Details 2) (Stock Options and Stock Appreciation Rights (SARs) [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Rate	Rate	Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Weighted average fair value of SARs granted	$6.72	$8.90	$9.68
Risk-free interest rate	0.67%	0.79%	1.74%
Expected volatility	50.40%	64.90%	63.30%
Dividend yield	0.00%	0.00%	0.00%
Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected life	'3 years 7 months	'4 years	'4 years
Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected life	'4 years 9 months	'5 years	'5 years

Stock_Compensation_Plans_Summa1

Stock Compensation Plans (Summary of Stock Option and SARs Activity) (Details 3) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Share-based Arrangements with Employees and Nonemployees [Abstract]	'
Outstanding at beginning of period	10,445,135
Weighted average exercise price, beginning of period	$14.75
Granted	720,859
Weighted average exercise price, granted	$16.95
Exercised	-1,970,426
Weighted average exercise price, exercised	$9.33
Forfeited	-113,509
Weighted average exercise price, forfeited	$17.31
Expired	-95,144
Weighted average exercise price, expired	$22.74
Outstanding at end of period	8,986,915
Weighted average exercise price, end of period	$16
Weighted average remaining contractual life of outstanding stock option and SARs	'3 years 3 months
Aggregate intrinsic value of stock option and SARs outstanding	$19,319
Exercisable at end of period	6,632,141
Weighted average price, exercisable at end of period	$15.51
Weighted average remaining contractual life of exercisable stock option and SARs	'2 years 8 months
Aggregate intrinsic value of exercisable options and SARs	$18,970

Stock_Compensation_Plans_Summa2

Stock Compensation Plans (Summary of Value of Stock Options and SARs) (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'	'	'
Intrinsic value of stock options exercised	$17,287	$17,315	$20,463
Grant-date fair value of stock options and SARs vested	$12,852	$26,391	$11,416

Stock_Compensation_Plans_Summa3

Stock Compensation Plans (Summary of Cash Received and Tax Benefit Realized) (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Including Stock Options [Abstract]	'	'	'
Cash received from stock option exercises	$5,487	$6,022	$4,685
Tax benefit realized for the exercises of stock options and SARs	$437	$458	$539

Stock_Compensation_Plans_Summa4

Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards - 2004 Restricted Stock Plan) (Details 6) (2004 Omnibus Stock and Incentive Plan, Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
2004 Omnibus Stock and Incentive Plan | Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Fair value of restricted stock vested	$21,529	$22,332	$12,355

Stock_Compensation_Plans_Summa5

Stock Compensation Plans (Summary of 2004 Restricted Stock Plan) (Details 7) (2004 Omnibus Stock and Incentive Plan, Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013
2004 Omnibus Stock and Incentive Plan | Restricted Stock [Member]	'
Nonvested Resticted Stock Outstanding [Line Items]	'
Nonvested at beginning of period	3,406,207
Weighted average grant-date fair value, beginning of period	$15.60
Granted	1,805,467
Weighted average grant-date fair value, granted	$16.96
Vested	-1,310,347
Weighted average grant-date fair value, vested	$16.21
Forfeited	-165,917
Weighted average grant-date fair value, forfeited	$17.23
Nonvested at end of period	3,735,410
Weighted average grant-date fair value, end of period	$15.97

Stock_Compensation_Plans_Summa6

Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards - Restricted Stock Legacy Encore Plan) (Details 8) (Encore Plan [Member], Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Encore Plan [Member] | Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Fair value of restricted stock vested	$512	$584	$2,259

Stock_Compensation_Plans_Summa7

Stock Compensation Plans (Summary of Encore Restricted Stock) (Details 9) (Encore Plan [Member], Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013
Encore Plan [Member] | Restricted Stock [Member]	'
Nonvested Resticted Stock Outstanding [Line Items]	'
Nonvested at beginning of period	56,258
Weighted average grant-date fair value, beginning of period	$15.43
Vested	-31,140
Weighted average grant-date fair value, vested	$15.43
Forfeited	-3,377
Weighted average grant-date fair value, forfeited	$15.43
Nonvested at end of period	21,741
Weighted average grant-date fair value, end of period	$15.43

Stock_Compensation_Plans_TSR_A

Stock Compensation Plans (TSR Award Assumptions) (Details 10) (Performance-based TSR Awards [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Rate	Rate
Performance-based TSR Awards [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Weighted average fair value of Performance-based TSR Award granted	$20.08	$24.68
Risk-free interest rate	0.41%	0.42%
Expected life	'3 years	'2 years 9 months
Expected volatility	42.30%	45.20%
Dividend yield	0.00%	0.00%

Stock_Compensation_Plans_Summa8

Stock Compensation Plans (Summary of Performance Based Equity Awards) (Details 11) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Performance-based TSR Awards [Member]	'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Nonvested at beginning of period	86,917		'
Weighted average grant-date fair value, beginning of period	$24.68		'
Granted	209,474		'
Weighted average grant-date fair value, granted	$20.08		$24.68
Vested	0		'
Weighted average grant-date fair value, vested	$0		'
Forfeited	0		'
Weighted average grant-date fair value, forfeited	$0		'
Nonvested at end of period	296,391		86,917
Weighted average grant-date fair value, end of period	$21.43		$24.68
Performance-based Operational Award [Member]	'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Nonvested at beginning of period	100,193		'
Weighted average grant-date fair value, beginning of period	$17.27		'
Granted	215,258		'
Weighted average grant-date fair value, granted	$16.77		'
Vested	-100,193	[1]	'
Weighted average grant-date fair value, vested	$17.27		'
Forfeited	-5,784		'
Weighted average grant-date fair value, forfeited	$16.77		'
Nonvested at end of period	209,474		'
Weighted average grant-date fair value, end of period	$16.77		'
Performance-based Operational Awards Granted in 2012 [Member]	'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'
Vesting level (percentage)	136.00%		'
[1]	During 2013, the 2012 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 136% of the number of target-level shares.

Stock_Compensation_Plans_Summa9

Stock Compensation Plans (Summary of Vesting Date Fair Value of Awards) (Details 12) (Performance-based Operational Award [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance-based Operational Award [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting date fair value of Performance-based Operational Awards	$2,541	$2,191	$10,892

Stock_Compensation_Plans_Detai

Stock Compensation Plans (Details Textual) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013
Stock Compensation Plans (Textuals) [Abstract]	'
Stock Options and SARs expiration period	'10 years
Performance equity awards [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Total compensation cost to be recognized in future periods	5.4
Weighted average period over which remaining cost will be recognized	'1 year 7 months
Performance equity awards [Member] | Minimum [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'1 year 3 months 0 days
Performance equity awards [Member] | Maximum [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years 3 months 0 days
Stock Options and Stock Appreciation Rights (SARs) [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Total compensation cost to be recognized in future periods	8
Weighted average period over which remaining cost will be recognized	'1 year 8 months
Stock Options and Stock Appreciation Rights (SARs) [Member] | Minimum [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years
Stock Options and Stock Appreciation Rights (SARs) [Member] | Maximum [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'4 years
2004 Omnibus Stock and Incentive Plan	'
Stock Compensation Plans (Textuals) [Abstract]	'
Maximum number of common stock shares authorized for issuance under Plan	34,500,000
Shares available for future awards	10,800,000
2004 Omnibus Stock and Incentive Plan | Restricted Stock [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Total compensation cost to be recognized in future periods	30.6
Weighted average period over which remaining cost will be recognized	'2 years 1 month
2004 Omnibus Stock and Incentive Plan | Restricted stock or performance vesting awards [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Maximum number of common stock shares authorized for issuance under Plan	27,200,000
Shares available for future awards	10,800,000
Encore Plan [Member] | Restricted Stock [Member]	'
Stock Compensation Plans (Textuals) [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'4 years

Commodity_Derivative_Contracts2

Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details)	Dec. 31, 2013
Year 2014 [Member] | Collar [Member] | NYMEX [Member] | Natural Gas Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	14,000
Derivative, Floor Price	4
Derivative, Cap Price	4.47
Weighted average floor price	4
Weighted average ceiling price	4.45
Year 2014 [Member] | Q1 [Member] | Swap [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	58,000
Derivative, Floor Price	91.67
Derivative, Cap Price	95.95
Weighted average swap price	93.53
Year 2014 [Member] | Q2 [Member] | Swap [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	58,000
Derivative, Floor Price	91.67
Derivative, Cap Price	95.95
Weighted average swap price	93.53
Year 2014 [Member] | Q3 [Member] | Swap [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	58,000
Derivative, Floor Price	90
Derivative, Cap Price	93.5
Weighted average swap price	92.52
Year 2014 [Member] | Q4 [Member] | Swap [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	58,000
Derivative, Floor Price	90
Derivative, Cap Price	93.5
Weighted average swap price	92.52
Year 2015 [Member] | Q1 [Member] | Collar [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	38,000
Derivative, Floor Price	80
Derivative, Cap Price	100.9
Weighted average floor price	80
Weighted average ceiling price	96.96
Year 2015 [Member] | Q1 [Member] | Collar [Member] | LLS [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	20,000
Derivative, Floor Price	85
Derivative, Cap Price	104
Weighted average floor price	85
Weighted average ceiling price	101.45
Year 2015 [Member] | Q2 [Member] | Collar [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	38,000
Derivative, Floor Price	80
Derivative, Cap Price	95.25
Weighted average floor price	80
Weighted average ceiling price	94.62
Year 2015 [Member] | Q2 [Member] | Collar [Member] | LLS [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	20,000
Derivative, Floor Price	85
Derivative, Cap Price	103
Weighted average floor price	85
Weighted average ceiling price	102.01
Year 2015 [Member] | Q3 [Member] | Collar [Member] | NYMEX [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	38,000
Derivative, Floor Price	80
Derivative, Cap Price	95.25
Weighted average floor price	80
Weighted average ceiling price	95.04
Year 2015 [Member] | Q3 [Member] | Collar [Member] | LLS [Member] | Crude Oil Contracts [Member]	'
Derivative [Line Items]	'
Volume per day	20,000
Derivative, Floor Price	85
Derivative, Cap Price	102.6
Weighted average floor price	85
Weighted average ceiling price	100.69

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Hierarchy) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Asset, Current	$5	$19,477
Derivative Asset, Noncurrent	9,942	36
Total Derivative Assets	9,947	19,513
Derivative Liability, Current	-53,822	-2,659
Derivative Liability, Noncurrent	-3,413	-23,781
Total Derivative Liabilities	-57,235	-26,440
Quoted Prices in Active Markets (Level 1) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Asset, Current	0	0
Derivative Asset, Noncurrent	0	0
Total Derivative Assets	0	0
Derivative Liability, Current	0	0
Derivative Liability, Noncurrent	0	0
Total Derivative Liabilities	0	0
Significant Other Observable Inputs, Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Asset, Current	5	19,477
Derivative Asset, Noncurrent	3,034	36
Total Derivative Assets	3,039	19,513
Derivative Liability, Current	-53,822	-2,659
Derivative Liability, Noncurrent	-3,214	-23,781
Total Derivative Liabilities	-57,036	-26,440
Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Asset, Current	0	0
Derivative Asset, Noncurrent	6,908	0
Total Derivative Assets	6,908	0
Derivative Liability, Current	0	0
Derivative Liability, Noncurrent	-199	0
Total Derivative Liabilities	($199)	$0

Fair_Value_Measurements_Level_

Fair Value Measurements (Level 3 Rollforward) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'	'
Fair value of Level 3 instruments, beginning of year	$0	$23,950
Unrealized gains on commodity derivative contracts included in net earnings	6,709	3,921
Receipts on settlement of commodity derivative contracts	0	-27,871
Fair value of Level 3 instruments, end of year	6,709	0
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date	$6,709	$0

Fair_Value_Measurements_Detail

Fair Value Measurements (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Sensitivity Analysis of Fair Value, Impact of 1 Percent Increase or Decrease in Level 3 Inputs	$100,000	'	'
Other Asset Impairment Charges	0	17,515,000	22,951,000
Long-term Debt, Fair Value	2,956,800,000	2,956,900,000	'
Faustina Investment Impairment [Member]	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Other Asset Impairment Charges	$15,100,000	'	'

Commitments_and_Contingencies_1

Commitments and Contingencies (Summary of Operating Lease Payments Paid and Received (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]	'	'	'
Operating lease payments	$37,211	$33,606	$52,317
Sublease rental receipts	$2,237	$2,685	$2,398

Commitments_and_Contingencies_2

Commitments and Contingencies (Future Non-Cancelable Pipeline and Capital Lease Payments) (Details 2) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Leases [Abstract]	'
Capital Leases in Year 1	$62,929
Capital Leases in Year 2	62,254
Capital Leases in Year 3	60,819
Capital Leases in Year 4	55,409
Capital Leases in Year 5	50,750
Capital Leases, Thereafter	280,272
Capital Leases, Total minimum lease payments	572,433
Capital Leases, Less: Amount representing interest	-215,748
Capital Leases, Present value of minimum lease payments	$356,685

Commitments_and_Contingencies_3

Commitments and Contingencies (Schedule of Future Operating Lease Payments) (Details 3) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Leases, Operating [Abstract]	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$11,695
Operating Leases, Future Minimum Payments, Due in Two Years	12,542
Operating Leases, Future Minimum Payments, Due in Three Years	12,510
Operating Leases, Future Minimum Payments, Due in Four Years	12,774
Operating Leases, Future Minimum Payments, Due in Five Years	12,730
Operating Leases, Future Minimum Payments, Due Thereafter	67,832
Operating Leases, Total minimum lease payments	$130,083

Commitments_and_Contingencies_4

Commitments and Contingencies (Leases) (Details Textuals 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Leases, Operating [Abstract]	'
Description of lease terms (in years)	'12 years
Expected future receipts under sublease agreements	$14.60

Commitments_and_Contingencies_5

Commitments and Contingencies (Commitments) (Details Textuals 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Anthropogenic CO2 Contracts [Member]	'
Long-term Purchase Commitment [Line Items]	'
Term of long-term purchase commitments (years)	'20 years
Oil price assumption for obligation estimate ($/Bbl)	90
Anthropogenic CO2 Contracts [Member] | Maximum [Member]	'
Long-term Purchase Commitment [Line Items]	'
Aggregate purchase obligation of CO2	$170
Anthropogenic CO2 Contracts [Member] | Minimum [Member]	'
Long-term Purchase Commitment [Line Items]	'
Aggregate purchase obligation of CO2	100
Volumetric production payments [Member]	'
Long-term Purchase Commitment [Line Items]	'
Term of long-term supply arrangement (years)	'15 years
Significant supply commitment yearly maximum volume required (MMcf/d)	119
Volumetric production payments [Member] | Maximum [Member]	'
Long-term Purchase Commitment [Line Items]	'
Significant supply commitment remaining volume committed (MMcf)	367,000
Riley Ridge [Member] | Helium Supply Arrangement [Member]	'
Long-term Purchase Commitment [Line Items]	'
Term of long-term supply arrangement (years)	'20 years
Maximum annual payment in event of shortfall	8
Maximum payment in event of shortfall	$46

Commitments_and_Contingencies_6

Commitments and Contingencies (Delhi Field Release) (Details Textuals 3) (Details) (USD $)	7 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013
Loss Contingencies [Line Items]	'	'
Environmental Remediation Expense	'	$114
Accrual for Environmental Loss Contingencies	22	22
Environmental Remediation Expense Incurred To Date	$92	'
Minimum [Member]	'	'
Loss Contingencies [Line Items]	'	'
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	33.33%	33.33%
Maximum [Member]	'	'
Loss Contingencies [Line Items]	'	'
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	66.67%	66.67%

Additional_Balance_Sheet_Detai2

Additional Balance Sheet Details (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Payable and Accrued Liabilities, Current [Abstract]	'	'
Accrued exploration and development costs	$100,564	$109,939
Accrued interest	68,871	60,698
Accounts payable	63,263	86,051
Accrued lease operating expenses	59,762	23,862
Accrued compensation	55,043	48,451
Taxes payable	28,019	27,523
Other	35,021	58,144
Total	$410,543	$414,668

Recovered_Sheet1

Additional balance Sheet Details (Detail Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Receivables [Abstract]	'	'
Allowance for doubtful accounts	$0.30	$0.30

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Supplemental Cash Flow Information [Abstract]	'		'		'
Cash paid for interest, expensed	$117,442,000		$137,950,000		$137,259,000
Cash paid for interest, capitalized	79,253,000		77,432,000		60,540,000
Cash paid for income taxes	28,895,000		99,194,000		45,912,000
Cash received from income tax refunds	-17,087,000		-38,004,000		-24,677,000
Non-cash investing activities:	'		'		'
Increase in asset retirement obligations	26,946,000		56,290,000		24,694,000
Increase (decrease) in liabilities for capital expenditures	-18,321,000		-26,882,000		74,697,000
Increase in Restricted Cash	0		1,262,559,000	[1]	0
Decrease in Restricted Cash	1,050,328,000	[2]	212,544,000	[2]	0
Non-core Gulf Coast Assets [Member]	'		'		'
Business Acquisition [Line Items]	'		'		'
Sales proceeds paid to qualified intermediary	'		212,500,000		'
Bakken Exchange Transaction [Member]	'		'		'
Business Acquisition [Line Items]	'		'		'
Sales proceeds paid to qualified intermediary	'		$1,050,000,000		'
[1]	During 2012, $212.5 million of proceeds from the sale of certain non-core assets in the Gulf Coast Region and $1.05 billion of the cash proceeds from the Bakken Exchange Transaction were paid by the respective purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.
[2]	During 2012 and 2013, proceeds from the sales of our oil and natural gas property dispositions in 2012, which were held by a qualified intermediary, were released in 2012 to fund the Thompson Field acquisition and in 2013 primarily to fund a portion of the CCA acquisition and certain post-closing costs under the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.

Subsequent_Events_Details_Text

Subsequent Events (Details Textuals) (USD $)	12 Months Ended			27 Months Ended	2 Months Ended		1 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Feb. 20, 2014	Jan. 28, 2014	Jan. 31, 2014	Jan. 03, 2014
					Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]
							Restricted Stock [Member]	Restricted Stock [Member]
							Rate
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'
Repurchase of common stock, shares	16,468,648	16,978,008	14,112,610	47,559,266	11,800,000	'	'	'
Total amount repurchased	$277,768	$266,657	$195,227	$739,652	$191,600	'	'	'
Treasury Stock Acquired, Average Cost Per Share	$16.87	$15.71	$13.83	$15.55	$16.17	'	'	'
Awards Granted	'	'	'	'	'	'	1,633,898	'
Value (per share) of restricted stock grant	'	'	'	'	'	'	'	$16.55
Equity award vesting percentage	'	'	'	'	'	'	33.00%	'
Dividends Payable, Amount Per Share	'	'	'	'	'	$0.06	'	'