Denbury (DNRWW) 10-Q7 Nov 132013 Q3 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
Document and Entity Information	Sep. 30, 2013	Oct. 31, 2013
Document And Company Information [Abstract]	'	'
Entity Registrant Name	'Denbury Resources Inc.	'
Entity Central Index Key	'0000945764	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-13	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Current Fiscal Year End Date	'--12-31	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	366,689,106

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets	'	'
Cash and cash equivalents	$26,548	$98,511
Restricted cash	0	1,050,015
Accrued production receivable	281,872	253,131
Trade and other receivables, net	83,904	81,971
Derivative assets	167	19,477
Deferred tax assets	34,422	29,156
Other current assets	12,881	10,493
Total current assets	439,794	1,542,754
Oil and natural gas properties (using full cost accounting)	'	'
Proved	8,314,196	6,963,211
Unevaluated	1,177,564	809,154
CO2 properties	1,094,699	1,032,653
Pipelines and plants	2,154,186	2,035,126
Other property and equipment	434,113	417,207
Less accumulated depletion, depreciation, amortization and impairment	-3,531,811	-3,180,241
Net property and equipment	9,642,947	8,077,110
Derivative assets	2,970	36
Goodwill	1,283,590	1,283,590
Other assets	240,344	235,852
Total assets	11,609,645	11,139,342
Current liabilities	'	'
Accounts payable and accrued liabilities	334,850	414,668
Oil and gas production payable	193,056	161,945
Derivative liabilities	40,261	2,842
Current maturities of long-term debt	35,581	36,966
Total current liabilities	603,748	616,421
Long-term liabilities	'	'
Long-term debt, net of current portion	3,238,969	3,104,462
Asset retirement obligations	123,994	102,730
Derivative liabilities	16,013	23,781
Deferred tax liabilities	2,328,131	2,153,452
Other liabilities	25,962	23,607
Total long-term liabilities	5,733,069	5,408,032
Commitments and contingencies (Note 7)	'	'
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; 408,779,349 and 406,163,194 shares issued, respectively	409	406
Paid-in capital in excess of par	3,173,394	3,136,461
Retained earnings	2,754,440	2,434,835
Accumulated other comprehensive loss	-294	-348
Treasury stock, at cost, 42,115,224 and 30,601,262 shares, respectively	-655,121	-456,465
Total stockholders' equity	5,272,828	5,114,889
Total liabilities and stockholders' equity	$11,609,645	$11,139,342

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Stockholders' equity	'	'
Preferred stock, par value	$0.00	$0.00
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	408,779,349	406,163,194
Treasury stock, shares	42,115,224	30,601,262

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues and other income	'	'	'	'
Oil, natural gas, and related product sales	$666,803	$588,156	$1,878,644	$1,813,798
CO2 sales and transportation fees	6,739	7,160	19,859	19,256
Interest income and other income	11,293	5,055	19,502	14,214
Total revenues and other income	684,835	600,371	1,918,005	1,847,268
Expenses	'	'	'	'
Lease operating expenses	180,967	130,485	542,067	392,960
Marketing expenses	13,131	14,728	36,259	37,776
CO2 discovery and operating expenses	4,120	1,176	11,261	8,443
Taxes other than income	49,267	40,012	132,218	122,518
General and administrative expenses	35,969	38,198	111,240	109,631
Interest, net of amounts capitalized of $19,768, $19,437, $64,752, and $57,357, respectively	34,501	37,827	101,137	115,745
Depletion, depreciation, and amortization	125,595	136,935	365,400	390,119
Derivatives expense (income)	80,446	61,631	46,874	-32,203
Loss on early extinguishment of debt	0	0	44,651	0
Impairment of assets	0	0	0	17,515
Other expenses	1,474	0	14,292	23,272
Total expenses	525,470	460,992	1,405,399	1,185,776
Income before income taxes	159,365	139,379	512,606	661,492
Income tax provision	57,311	54,012	193,001	250,793
Net income	$102,054	$85,367	$319,605	$410,699
Net income per common share	'	'	'	'
Basic	$0.28	$0.22	$0.87	$1.06
Diluted	$0.28	$0.22	$0.86	$1.05
Weighted average common shares outstanding	'	'	'	'
Basic	366,088	387,512	368,101	387,015
Diluted	369,142	390,909	371,316	390,854

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Expenses	'	'	'	'
Capitalized interest	$19,768	$19,437	$64,752	$57,357

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Comprehensive Income [Abstract]	'	'	'	'
Net income	$102,054	$85,367	$319,605	$410,699
Other comprehensive income, net of income tax:	'	'	'	'
Interest rate lock derivative contracts reclassified to income, net of tax of $11, $11, $30 and $32, respectively	17	17	54	52
Total other comprehensive income	17	17	54	52
Comprehensive income	$102,071	$85,384	$319,659	$410,751

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other comprehensive income, net of income tax:	'	'	'	'
Tax for interest rate lock derivative contracts reclassified to income	$11	$11	$30	$32

Condensed_Consolidated_Stateme4

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash flow from operating activities:	'	'
Net income	$319,605	$410,699
Adjustments to reconcile net income to cash flow from operating activities:	'	'
Depletion, depreciation, and amortization	365,400	390,119
Deferred income taxes	169,634	216,959
Stock-based compensation	23,774	22,662
Noncash fair value derivative adjustments	46,296	-19,757
Loss on early extinguishment of debt	44,651	0
Amortization of debt issuance costs and discounts	10,581	11,021
Impairment of assets	0	17,515
Other, net	-3,570	15,087
Changes in assets and liabilities, net of effects from acquisitions:	'	'
Accrued production receivable	-34,910	3,221
Trade and other receivables	-756	11,010
Other current and long-term assets	-1,199	8,218
Accounts payable and accrued liabilities	52,672	-30,127
Oil and natural gas production payable	31,111	5,014
Other liabilities	-11,080	-35,515
Net cash provided by operating activities	1,012,209	1,026,126
Cash flow used in investing activities:	'	'
Oil and natural gas capital expenditures	-688,270	-848,618
Acquisitions of oil and natural gas properties	-1,896	-155,636
Bakken exchange transaction	-10,385	0
CO2 capital expenditures	-72,929	-93,945
Pipelines and plants capital expenditures	-136,654	-231,459
Purchases of other assets	-29,680	-18,666
Net proceeds from sales of oil and natural gas properties and equipment	6,312	33,973
Proceeds from sale of short-term investments	0	83,545
Other	-18,201	-7,166
Net cash used in investing activities	-951,703	-1,237,972
Cash flow provided by (used in) financing activities:	'	'
Bank repayments	-1,170,000	-970,000
Bank borrowings	780,000	1,210,000
Repayment of senior subordinated notes	-651,270	0
Premium paid on repayment of senior subordinated notes	-36,475	0
Proceeds from issuance of senior subordinated notes	1,200,000	0
Costs of debt financing	-20,026	-17
Common stock repurchase program	-215,197	-16,747
Other	-19,501	-6,049
Net cash provided by (used in) financing activities	-132,469	217,187
Net increase (decrease) in cash and cash equivalents	-71,963	5,341
Cash and cash equivalents at beginning of period	98,511	18,693
Cash and cash equivalents at end of period	$26,548	$24,034

Basis_of_Presentation

Basis of Presentation

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company. We are the largest combined oil and natural gas producer in both Mississippi and Montana, own the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast 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.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2012 (the "Form 10-K"). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company,” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2013, our consolidated results of operations for the three and nine months ended September 30, 2013 and 2012, and our consolidated cash flows for the nine months ended September 30, 2013 and 2012.

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.

Net Income per Common Share

Basic net income per common share is computed by dividing 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-based equity awards. For the three and nine months ended September 30, 2013 and 2012, there were no adjustments to net income for purposes of calculating basic or diluted net income per common share.

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

In thousands

2013

2012

2013

2012

Basic weighted average common shares outstanding

366,088

387,512

368,101

387,015

Potentially dilutive securities:

Restricted stock, stock options, SARs and performance-based equity awards

3,054

3,397

3,215

3,839

Diluted weighted average common shares outstanding

369,142

390,909

371,316

390,854

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 shares for the three and nine months ended September 30, 2013, and 5.4 million and 4.1 million shares for the three and nine months ended September 30, 2012, respectively, were not included in the computation of diluted net income per share as their effect would have been antidilutive.

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 Financial Accounting Standards Board Codification ("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	9 Months Ended
Acquisitions and Divestitures	Sep. 30, 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. We funded the acquisition 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. As such, 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.

	The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 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
	Cash consideration (1)		$	1,001,707


	Fair value of assets acquired and liabilities assumed:
	Fair value of assets acquired and liabilities assumed:
	Oil and natural gas properties
	Oil and natural gas properties
	Proved		783,507
	Proved		783,507
	Unevaluated		222,820
	Unevaluated		222,820
	Other assets		2,589
	Other assets		2,589
	Asset retirement obligations		(7,209		)
			$	1,001,707
			$	1,001,707


	-1	$989.0 million of this cash consideration was paid through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

	For the three months ended September 30, 2013 and for the period from March 27, 2013 to September 30, 2013, we recognized $97.1 million and $189.8 million of oil, natural gas, and related product sales, respectively, from the property interests acquired in the CCA acquisition. For the three months ended September 30, 2013 and for the period from March 27, 2013 to September 30, 2013, we recognized $70.9 million and $138.8 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), respectively, 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. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 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
	Fair value of net assets transferred		$	1,866,107


	Fair value of assets acquired and liabilities assumed:
	Fair value of assets acquired and liabilities assumed:
	Cash		1,277,041
	Cash		1,277,041
	Oil and natural gas properties
	Oil and natural gas properties
	Proved		182,289
	Proved		182,289
	Unevaluated		90,690
	Unevaluated		90,690
	CO2 properties		314,505
	CO2 properties		314,505
Other property and equipment		23,424
Other property and equipment		23,424
Other assets		477
Other assets		477
Other liabilities		(8,528		)
Asset retirement obligations		(13,791		)
		$	1,866,107
		$	1,866,107

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, which is an enhanced oil recovery field that we are currently flooding with CO2 and which is the current terminus of the Green Pipeline which transports CO2 both from the Jackson Dome area, located 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.

Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other income and net income are presented as if the CCA Acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
In thousands, except per share data		2013				2012		2013		2012
Pro forma total revenues and other income		$	684,835			$	598,340	$	2,000,179	$	1,925,385
Pro forma total revenues and other income		$	684,835			$	598,340	$	2,000,179	$	1,925,385
Pro forma net income		102,054				92,857		347,624		461,009
Pro forma net income		102,054				92,857		347,624		461,009
Pro forma net income per common share
Basic		$	0.28			$	0.24	$	0.94	$	1.19
Basic		$	0.28			$	0.24	$	0.94	$	1.19
Diluted		0.28				0.24		0.94		1.18
Diluted		0.28				0.24		0.94		1.18

Other 2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012 and proceeds received after final closing adjustments totaled $68.5 million. 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.

LongTerm_Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Note 3. Long-Term Debt

	The following long-term debt and capital lease obligations were outstanding as of the dates indicated:


		September 30,			December 31,
	In thousands	2013			2012
	Bank Credit Agreement	$	310,000		$	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 $19 and $25, respectively	3,826			3,832

	Pipeline financings	229,619			236,244

	Capital lease obligations	134,832			158,260

	Total	3,274,550			3,141,428

	Less: current obligations	(35,581		)	(36,966		)
	Long-term debt and capital lease obligations	$	3,238,969		$	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.

	4 5/8% Senior Subordinated Notes due 2023

	In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. The net proceeds, after issuance costs, of approximately $1.18 billion were used to repurchase or redeem a portion of our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes"), all of our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes") (see Repurchase and Redemption of 9½% Notes and 9¾% Notes below) and to pay down a portion of outstanding borrowings on our Bank Credit Facility (as defined below).

	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 the following redemption prices: 102.313% on or after January 15, 2018; 101.542% on or after January 15, 2019; 100.771% on or after January 15, 2020; and 100% on or after January 15, 2021. 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% 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. The indenture for the 2023 Notes (the "2023 Indenture") contains certain restrictions on our ability to take or permit certain actions, including restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. Although the covenants contained in our other senior subordinated notes indentures are generally consistent with those contained in our 2023 Indenture, the 2023 Indenture covenants permit us in certain circumstances to make restricted payments exceeding the amount allowed under our other senior subordinated notes indentures. Under the 2023 Indenture, these restricted payments, which include share repurchases and dividend payments, do not reduce our restricted payment limitation, provided we maintain (both before and after giving effect to any such payment) a predefined leverage ratio of at least 2.5 to 1. The leverage ratio represents the ratio of total debt to EBITDA, both as defined within the 2023 Indenture.

	Repurchase and Redemption of 9½% Notes and 9¾% Notes


	On January 22, 2013, we commenced cash tender offers to purchase the outstanding $426.4 million principal amount of our 9¾% Notes at 105.425% of par and the outstanding $224.9 million principal amount of our 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. We received sufficient consents in the solicitation to amend the indenture governing the 9½% Notes to eliminate most of the restrictive covenants and certain events of default. The purchases under these tender offers were funded by a portion of the proceeds received from the issuance of our 2023 Notes. The tender offers expired on February 19, 2013.

	On February 5, 2013, we issued a notice of redemption for the remaining $234.7 million principal amount outstanding of our 9¾% Notes at 104.875% of par, and on March 7, 2013, we repurchased all of the remaining 9¾% Notes outstanding. On March 28, 2013, we issued a notice of redemption for the remaining $38.2 million principal amount outstanding of our 9½% Notes at 104.75% of par, and on May 1, 2013, we repurchased all of the remaining 9½% Notes outstanding.

	We recognized a loss associated with the debt repurchases of $44.7 million during the nine months ended September 30, 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 Unaudited Condensed Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt".

	$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., 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 and upon requested special redeterminations. The borrowing base is adjusted at the banks' discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period not to exceed four months. As part of the semi-annual review completed in late October 2013 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion. Our next semi-annual redetermination is scheduled to occur on or around May 1, 2014. The weighted average interest rate on borrowings under this revolving credit facility, evidenced by the Bank Credit Agreement (the "Bank Credit Facility") was 1.7% as of September 30, 2013. We incur a commitment fee on the unused portion of the Bank Credit Facility of either 0.375% or 0.5%, based on the ratio of outstanding borrowings under the Bank Credit Facility to the borrowing base. Loans under the Bank Credit Facility mature in May 2016.

Share_Repurchase_Program

Share Repurchase Program	9 Months Ended
Share Repurchase Program	Sep. 30, 2013
Stockholders' Equity Note [Abstract]	'
Share Repurchase Program	'
	Note 4. Share Repurchase Program

	Under our board-authorized share repurchase program, we repurchased 6.7 million shares of Denbury common stock for $114.8 million during the three months ended September 30, 2013 and 11.7 million shares of Denbury common stock for $200.0 million during the nine months ended September 30, 2013. Since commencement of the share repurchase program in October 2011 through September 30, 2013, we have repurchased a total of 42.8 million shares of Denbury common stock for $661.9 million, or $15.48 per share. As of September 30, 2013, we had $109.3 million of remaining repurchases authorized under our share repurchase program.

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments and Hedging Activities	'
	Note 5. Derivative Instruments

	Oil and Natural Gas 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 “Derivatives expense (income)” in our Unaudited Condensed 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, costless collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted oil production approximately 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 continuing worldwide economic uncertainties and commodity price volatility. Because our current and foreseeable production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program, and have no natural gas derivative contracts for 2013 or beyond.

	The following is a summary of “Derivatives expense (income)” included in our Unaudited Condensed Consolidated Statements of Operations for the periods indicated:


			Three Months Ended								Nine Months Ended
			September 30,								September 30,
	In thousands		2013				2012				2013				2012
	Oil
	Cash payment on settlements of derivative contracts		$	662			$	641			$	662			$	9,580

	Noncash fair value adjustments to derivative contracts – expense (income)		79,784				60,726				46,212				(37,752		)

	Total derivatives expense (income) – oil		80,446				61,367				46,874				(28,172		)

	Natural Gas

	Cash receipt on settlements of derivative contracts		—				(6,910		)		—				(21,941		)

	Noncash fair value adjustments to derivative contracts – expense		—				7,174				—				17,910

	Total derivatives expense (income) – natural gas		—				264				—				(4,031		)

	Derivatives expense (income)		$	80,446			$	61,631			$	46,874			$	(32,203	)


	Commodity Derivative Contracts Not Classified as Hedging Instruments

	The following table presents outstanding oil derivative contracts with respect to future production as of September 30, 2013:


											Contract Prices per Barrel of Oil
					Type of		Pricing		Volume							Weighted Average Price
	Year		Months		Contract		Index		(Barrels per day)		Range					Floor			Ceiling

	2013		Oct – Dec		Collar		NYMEX		54,000		$	80	–	127.5		$	80		$	117.53



	2014		Jan – Mar		Collar		NYMEX		58,000		$	80	–	104.5		$	80		$	102.11

			Apr – June		Collar		NYMEX		58,000			80	–	104.5		80			102.11

			July – Sept		Collar		NYMEX		58,000			80	–	100		80			97.73

			Oct – Dec		Collar		NYMEX		58,000			80	–	100		80			97.73



	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		30,000			80	–	95.25		80			95.06

		July – Sept		Collar		LLS		16,000			85	–	102.6		85			101.11


Additional Disclosures about Derivative Instruments

At September 30, 2013 and December 31, 2012, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:


				Estimated Fair Value
				Asset (Liability)
				September 30,				December 31,
Type of Contract		Balance Sheet Location		2013				2012
				In thousands
Derivative assets
Crude oil contracts		Derivative assets – current		$	167			$	19,477

Crude oil contracts		Derivative assets – long-term		2,970				36

Derivative liabilities

Crude oil contracts		Derivative liabilities – current		(40,261		)		(2,659		)
Deferred premiums		Derivative liabilities – current		—				(183		)

Crude oil contracts		Derivative liabilities – long-term		(16,013		)		(23,781		)
Total derivatives not designated as hedging instruments				$	(53,137	)		$	(7,110	)

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 September 30, 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.

Fair_Value_Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Note 6. 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. We currently have no Level 1 recurring measurements.


	•	Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing. 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 September 30, 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 September 30, 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 the periods indicated:


			Fair Value Measurements Using:
	In thousands		Quoted Prices		Significant			Significant			Total
			in Active		Other			Unobservable
			Markets		Observable			Inputs
			(Level 1)		Inputs			(Level 3)
					(Level 2)
	September 30, 2013
	Assets:
	Oil derivative contracts		$	—	$	1,251		$	1,886		$	3,137

	Liabilities:

	Oil derivative contracts		—		(54,534		)	(1,740		)	(56,274		)

	Total		$	—	$	(53,283	)	$	146		$	(53,137	)

	December 31, 2012

	Assets:

	Oil derivative contracts		$	—	$	19,513		$	—		$	19,513

	Liabilities:

	Oil derivative contracts		—		(26,440		)	—			(26,440		)

	Total		$	—	$	(6,927	)	$	—		$	(6,927	)


	Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

	During the first quarter of 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of Faustina Hydrogen Products LLC, which impairment was classified as “Impairment of assets” in the Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2012. The inputs used to determine fair value of the investment included the projected future cash flows of the plant and risk-adjusted rate of return that we estimated would be used by a market participant in valuing the asset. These inputs are unobservable within the marketplace and therefore considered Level 3 within the fair value hierarchy. However, as there are currently no expected future cash flows associated with the plant, the preferred stock was determined to have no value.

	Other Fair Value Measurements

	The carrying value of our 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 September 30, 2013 and December 31, 2012, excluding pipeline financing and capital lease obligations, was $2.921 billion and $2.957 billion, 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	9 Months Ended
Commitments and Contingencies	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Note 7. Commitments and Contingencies

	We are involved in various lawsuits, claims and other regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. 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. We are also subject to audits for sales and use taxes and severance taxes in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe.

	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 had been previously plugged and abandoned by a prior operator of the field. We currently expect that our ongoing remediation efforts will be completed during the fourth quarter of 2013; however we will continue to monitor the area for a period of time thereafter to ensure the remediation efforts were successful.

	During the three and nine months ended September 30, 2013, we recorded $28.0 million and $98.0 million, respectively, of lease operating expenses related to this release in our Unaudited Condensed Consolidated Statement of Operations, and as of September 30, 2013 we had a corresponding $31.3 million liability classified as “Accounts payable and accrued liabilities” in our Unaudited Condensed Consolidated Balance Sheet. These expenses represent our current estimate of the costs to remediate this release based on actual costs incurred through October 31, 2013 of approximately $85 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 costs of certain of our remediation-related activities which have been identified and/or begun but which have not been completed, 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 which we believe cover certain of the costs and damages related to the release, and we currently 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 such recoveries in our financial statements as of September 30, 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.

Basis_of_Presentation_Policies

Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Organization and Nature of Operations

Interim Financial Statements - Basis of Accounting

Interim Financial Statements

Interim Financial Statements - Use of Estimates

Reclassifications

Net Income Per Common Share

Net Income per Common Share

The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:

Three Months Ended September 30,

Nine Months Ended September 30,

In thousands

2013

2012

2013

2012

Basic weighted average common shares outstanding

366,088

387,512

368,101

387,015

Potentially dilutive securities:

Restricted stock, stock options, SARs and performance-based equity awards

3,054

3,397

3,215

3,839

Diluted weighted average common shares outstanding

369,142

390,909

371,316

390,854

New Accounting Pronouncements

Recent Accounting Pronouncements

Derivatives

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 “Derivatives expense (income)” in our Unaudited Condensed 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, costless collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted oil production approximately 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 continuing worldwide economic uncertainties and commodity price volatility. Because our current and foreseeable production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program, and have no natural gas derivative contracts for 2013 or beyond.

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.

Fair Value of Financial Instruments

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. We currently have no Level 1 recurring measurements.

•

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing. 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 September 30, 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 September 30, 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.

Basis_of_Presentation_Tables

Basis of Presentation (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Weighted average shares used in the basic and diluted net income per common share	'
	The following is a reconciliation of the weighted average shares outstanding used in the basic and diluted net income per common share calculations for the periods indicated:


		Three Months Ended September 30,		Nine Months Ended September 30,
	In thousands	2013	2012	2013	2012
	Basic weighted average common shares outstanding	366,088	387,512	368,101	387,015

	Potentially dilutive securities:

	Restricted stock, stock options, SARs and performance-based equity awards	3,054	3,397	3,215	3,839

	Diluted weighted average common shares outstanding	369,142	390,909	371,316	390,854

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	9 Months Ended
Acquisitions and Divestitures (Tables)	Sep. 30, 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 CCA Acquisition, Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2012:


			Three Months Ended					Nine Months Ended
			September 30,					September 30,
	In thousands, except per share data		2013			2012		2013		2012
	Pro forma total revenues and other income		$	684,835		$	598,340	$	2,000,179	$	1,925,385
	Pro forma total revenues and other income		$	684,835		$	598,340	$	2,000,179	$	1,925,385
	Pro forma net income		102,054			92,857		347,624		461,009
	Pro forma net income		102,054			92,857		347,624		461,009
	Pro forma net income per common share
	Basic		$	0.28		$	0.24	$	0.94	$	1.19
	Basic		$	0.28		$	0.24	$	0.94	$	1.19
	Diluted		0.28			0.24		0.94		1.18
	Diluted		0.28			0.24		0.94		1.18
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
	Cash consideration (1)		$	1,001,707


	Fair value of assets acquired and liabilities assumed:
	Fair value of assets acquired and liabilities assumed:
	Oil and natural gas properties
	Oil and natural gas properties
	Proved		783,507
	Proved		783,507
	Unevaluated		222,820
	Unevaluated		222,820
	Other assets		2,589
	Other assets		2,589
	Asset retirement obligations		(7,209		)
			$	1,001,707
			$	1,001,707


	-1	$989.0 million of this cash consideration was paid through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.
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
	Fair value of net assets transferred		$	1,866,107


	Fair value of assets acquired and liabilities assumed:
	Fair value of assets acquired and liabilities assumed:
	Cash		1,277,041
	Cash		1,277,041
	Oil and natural gas properties
	Oil and natural gas properties
	Proved		182,289
	Proved		182,289
	Unevaluated		90,690
	Unevaluated		90,690
	CO2 properties		314,505
	CO2 properties		314,505
	Other property and equipment		23,424
	Other property and equipment		23,424
	Other assets		477
	Other assets		477
	Other liabilities		(8,528		)
	Asset retirement obligations		(13,791		)
			$	1,866,107
			$	1,866,107

LongTerm_Debt_Tables

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Components of Long-Term Debt	'
	The following long-term debt and capital lease obligations were outstanding as of the dates indicated:


		September 30,			December 31,
	In thousands	2013			2012
	Bank Credit Agreement	$	310,000		$	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 $19 and $25, respectively	3,826			3,832

	Pipeline financings	229,619			236,244

	Capital lease obligations	134,832			158,260

	Total	3,274,550			3,141,428

	Less: current obligations	(35,581		)	(36,966		)
	Long-term debt and capital lease obligations	$	3,238,969		$	3,104,462

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity derivative expense (income) included in our Unaudited Condensed Consolidated Statements of Operations	'
	The following is a summary of “Derivatives expense (income)” included in our Unaudited Condensed Consolidated Statements of Operations for the periods indicated:


		Three Months Ended								Nine Months Ended
		September 30,								September 30,
	In thousands	2013				2012				2013				2012
	Oil
	Cash payment on settlements of derivative contracts	$	662			$	641			$	662			$	9,580

	Noncash fair value adjustments to derivative contracts – expense (income)	79,784				60,726				46,212				(37,752		)

	Total derivatives expense (income) – oil	80,446				61,367				46,874				(28,172		)

	Natural Gas

	Cash receipt on settlements of derivative contracts	—				(6,910		)		—				(21,941		)

	Noncash fair value adjustments to derivative contracts – expense	—				7,174				—				17,910

	Total derivatives expense (income) – natural gas	—				264				—				(4,031		)

	Derivatives expense (income)	$	80,446			$	61,631			$	46,874			$	(32,203	)

Commodity derivative contracts not classified as hedging instruments	'
	The following table presents outstanding oil derivative contracts with respect to future production as of September 30, 2013:


										Contract Prices per Barrel of Oil
				Type of		Pricing		Volume							Weighted Average Price
	Year	Months		Contract		Index		(Barrels per day)		Range					Floor		Ceiling

	2013	Oct – Dec		Collar		NYMEX		54,000		$	80	–	127.5		$	80	$	117.53



	2014	Jan – Mar		Collar		NYMEX		58,000		$	80	–	104.5		$	80	$	102.11

		Apr – June		Collar		NYMEX		58,000			80	–	104.5		80		102.11

		July – Sept		Collar		NYMEX		58,000			80	–	100		80		97.73

		Oct – Dec		Collar		NYMEX		58,000			80	–	100		80		97.73



	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		30,000			80	–	95.25		80		95.06

		July – Sept		Collar		LLS		16,000			85	–	102.6		85		101.11

Derivative financial instruments included in our Unaudited Condensed Consolidated Balance Sheet	'
	At September 30, 2013 and December 31, 2012, we had derivative financial instruments recorded in our Unaudited Condensed Consolidated Balance Sheets as follows:


				Estimated Fair Value
				Asset (Liability)
				September 30,				December 31,
	Type of Contract	Balance Sheet Location		2013				2012
				In thousands
	Derivative assets
	Crude oil contracts	Derivative assets – current		$	167			$	19,477

	Crude oil contracts	Derivative assets – long-term		2,970				36

	Derivative liabilities

	Crude oil contracts	Derivative liabilities – current		(40,261		)		(2,659		)
	Deferred premiums	Derivative liabilities – current		—				(183		)

	Crude oil contracts	Derivative liabilities – long-term		(16,013		)		(23,781		)
	Total derivatives not designated as hedging instruments			$	(53,137	)		$	(7,110	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 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 the periods indicated:


		Fair Value Measurements Using:
	In thousands	Quoted Prices		Significant			Significant			Total
		in Active		Other			Unobservable
		Markets		Observable			Inputs
		(Level 1)		Inputs			(Level 3)
				(Level 2)
	September 30, 2013
	Assets:
	Oil derivative contracts	$	—	$	1,251		$	1,886		$	3,137

	Liabilities:

	Oil derivative contracts	—		(54,534		)	(1,740		)	(56,274		)

	Total	$	—	$	(53,283	)	$	146		$	(53,137	)

	December 31, 2012

	Assets:

	Oil derivative contracts	$	—	$	19,513		$	—		$	19,513

	Liabilities:

	Oil derivative contracts	—		(26,440		)	—			(26,440		)

	Total	$	—	$	(6,927	)	$	—		$	(6,927	)

Basis_of_Presentation_Reconcil

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Weighted average shares used in the basic and diluted net income per common share	'	'	'	'
Basic weighted average common shares outstanding	366,088	387,512	368,101	387,015
Potentially dilutive securities:	'	'	'	'
Restricted stock, stock options, SARs, and performance-based equity awards	3,054	3,397	3,215	3,839
Diluted weighted average common shares outstanding	369,142	390,909	371,316	390,854

Basis_of_Presentation_Details_

Basis of Presentation (Details Textuals)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share [Abstract]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Total	3.6	5.4	3.6	4.1

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (CCA PPA) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013		Sep. 30, 2013
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Cedar Creek Anticline [Member]		Cedar Creek Anticline Portion Of Cash Consideration Paid Through A Qualified Intermediary [Member]
Business Acquisition [Line Items]	'	'	'		'
Cash consideration	'	'	$1,001,707	[1]	$989,000
Proved	8,314,196	6,963,211	783,507		'
Unevaluated	1,177,564	809,154	222,820		'
Other assets	'	'	2,589		'
Asset retirement obligations	-123,994	-102,730	-7,209		'
Business Acquisition, Purchase Price Allocation, Assets Acquired Less (Liabilities Assumed)	'	'	1,001,707		'
Restricted cash	$0	$1,050,015	'		'

[1]	$989.0 million of this cash consideration was paid through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures Acquisitions and Divestitures (Bakken PPA) (Details 1) (USD $)	10 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Business Acquisition [Line Items]	'	'
Proved	$8,314,196	$6,963,211
Unevaluated	1,177,564	809,154
CO2 properties	1,094,699	1,032,653
Asset retirement obligations	-123,994	-102,730
Bakken Exchange Transaction [Member]	'	'
Business Acquisition [Line Items]	'	'
Fair value of net assets transferred	1,866,107	'
Cash	1,277,041	1,300,000
Proved	182,289	'
Unevaluated	90,690	'
CO2 properties	314,505	'
Other property and equipment	23,424	'
Other assets	477	'
Other liabilities	-8,528	'
Asset retirement obligations	-13,791	'
Business Acquisition, Purchase Price Allocation, Assets Acquired Less (Liabilities Assumed)	$1,866,107	'

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures Acquisitions and Divestitures (Pro Forma) (Details 2) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Business Acquisition [Line Items]	'	'	'	'
Pro forma total revenues and other income	$684,835	$598,340	$2,000,179	$1,925,385
Pro forma net income	$102,054	$92,857	$347,624	$461,009
Pro forma net income per common share [Abstract]	'	'	'	'
Basic	$0.28	$0.24	$0.94	$1.19
Diluted	$0.28	$0.24	$0.94	$1.18

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures (Details Textuals) (USD $)

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

6 Months Ended

1 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2012

Feb. 29, 2012

Sep. 30, 2012

Apr. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Jan. 31, 2013

Thompson Field [Member]

Non-core Gulf Coast Assets [Member]

Paradox Basin [Member]

Bakken Exchange Transaction [Member]

Cedar Creek Anticline [Member]

Rate

Scenario, Plan [Member]

Scenario, Actual [Member]

Rate

Scenario, Plan [Member]

Business Acquisition [Line Items]

Business Acquisition, Cost of Acquired Entity, Cash Paid

$366,200,000

$1,001,707,000

[1]

$1,050,000,000

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

97,100,000

189,800,000

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

70,900,000

138,800,000

Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents

1,300,000,000

1,277,041,000

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 Gas Property and Equipment

6,312,000

33,973,000

141,800,000

75,000,000

68,500,000

Gain (Loss) on Sale of Property

[1]

$989.0 million of this cash consideration was paid through a qualified intermediary from cash placed in qualifying trust accounts from a portion of the proceeds received from the Bakken Exchange Transaction (as defined below) in order to enable a like-kind-exchange transaction for federal income tax purposes. As such, this amount is not reflected as a cash payment to purchase oil and natural gas properties in our Unaudited Condensed Consolidated Statement of Cash Flows.

LongTerm_Debt_Components_of_Lo

Long-Term Debt (Components of Long-Term Debt) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Bank Credit Agreement	$310,000	$700,000
Pipeline financings	229,619	236,244
Capital lease obligations	134,832	158,260
Total	3,274,550	3,141,428
Less current obligations	-35,581	-36,966
Long-term debt and capital lease obligations	3,238,969	3,104,462
9.5% Senior Subordinated Notes due 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Subordinated Notes	0	234,038
Including premium of	0	9,118
Debt Instrument, Interest Rate, Stated Percentage	9.50%	'
9.75% Senior Subordinated Notes due 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior Subordinated Notes	0	412,781
Including discount of	0	13,569
Debt Instrument, Interest Rate, Stated Percentage	9.75%	'
8.25% 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	3,826	3,832
Including premium of	$19	$25

LongTerm_Debt_Details_Textuals

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

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Feb. 28, 2013

Sep. 30, 2013

Dec. 31, 2012

Mar. 07, 2013

Feb. 19, 2013

Jan. 22, 2013

Feb. 19, 2013

1-May-13

Jan. 22, 2013

Sep. 30, 2013

Oct. 31, 2013

Mar. 31, 2010

Sep. 30, 2013

Rate

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

9.75% Senior Subordinated Notes due 2016 [Member]

9.5% Senior Subordinated Notes due 2016 [Member]

Bank Credit Agreement [Member]

Debt Instrument, Redemption, Period One [Member]

Debt Instrument, Redemption, Period Two [Member]

Debt Instrument, Redemption, Period Three [Member]

Debt Instrument, Redemption, Period Four [Member]

Initial Redemption Period with Proceeds from Equity Offering [Member]

Initial Redemption Period with Make-Whole Premium [Member]

Rate

Minimum [Member]

Maximum [Member]

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

Rate

Long Term Debt (Textuals) [Abstract]

Interest in guarantor subsidiaries

100.00%

Face Value of Notes Issued

$1,200,000,000

Debt Instrument, Interest Rate, Stated Percentage

4.63%

Selling Price Of Debt Instrument

100.00%

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

1,180,000,000

Debt Instrument, Redemption Price, Percentage

104.88%

105.43%

106.87%

104.75%

102.31%

101.54%

100.77%

100.00%

104.63%

100.00%

Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed

35.00%

100.00%

Leverage Ratio Requirement for Restricted Payments

'at least 2.5 to 1

Subordinated Debt

1,200,000,000

426,400,000

224,900,000

Debt Instrument, Repurchased Face Amount

234,700,000

191,700,000

186,700,000

38,200,000

Loss on early extinguishment of debt

44,651,000

$1.6 Billion Revolving Credit Facility [Abstract]

Borrowing Base of Denbury credit facility

$1,600,000,000

Weighted average interest rate on Bank Credit Facility

1.70%

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.38%

0.50%

Share_Repurchase_Program_Detai

Share Repurchase Program (Details Textuals) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended	24 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
Stockholders' Equity Note [Abstract]	'	'	'	'
Treasury Stock, Shares, Acquired	'	6.7	11.7	42.8
Treasury Stock, Value, Acquired, Cost Method	'	$114.80	$200	$661.90
Treasury Stock Acquired, Average Cost Per Share	'	'	'	$15.48
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$109.30	'	'	'

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities (Summary of Derivative Income/Expense) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Loss (Gain) [Line Items]	'	'	'	'
Total derivatives expense (income)	$80,446	$61,631	$46,874	($32,203)
Crude Oil Contracts [Member]	'	'	'	'
Derivative Instruments, Loss (Gain) [Line Items]	'	'	'	'
Cash payment (receipt) on settlements of derivative contracts	662	641	662	9,580
Noncash fair value adjustments to derivative contracts	79,784	60,726	46,212	-37,752
Total derivatives expense (income)	80,446	61,367	46,874	-28,172
Natural Gas Contracts [Member]	'	'	'	'
Derivative Instruments, Loss (Gain) [Line Items]	'	'	'	'
Cash payment (receipt) on settlements of derivative contracts	0	-6,910	0	-21,941
Noncash fair value adjustments to derivative contracts	0	7,174	0	17,910
Total derivatives expense (income)	$0	$264	$0	($4,031)

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities (Commodity Derivatives Outstanding) (Details)	Sep. 30, 2013
Year 2013 [Member] \| Q4 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	54,000
Derivative, Floor Price	80
Derivative, Cap Price	127.5
Average floor price	80
Average ceiling price	117.53
Year 2014 [Member] \| Q1 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	58,000
Derivative, Floor Price	80
Derivative, Cap Price	104.5
Average floor price	80
Average ceiling price	102.11
Year 2014 [Member] \| Q2 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	58,000
Derivative, Floor Price	80
Derivative, Cap Price	104.5
Average floor price	80
Average ceiling price	102.11
Year 2014 [Member] \| Q3 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	58,000
Derivative, Floor Price	80
Derivative, Cap Price	100
Average floor price	80
Average ceiling price	97.73
Year 2014 [Member] \| Q4 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	58,000
Derivative, Floor Price	80
Derivative, Cap Price	100
Average floor price	80
Average ceiling price	97.73
Year 2015 [Member] \| Q1 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	38,000
Derivative, Floor Price	80
Derivative, Cap Price	100.9
Average floor price	80
Average ceiling price	96.96
Year 2015 [Member] \| Q1 [Member] \| LLS [Member]	'
Derivative [Line Items]	'
Volume per Day	20,000
Derivative, Floor Price	85
Derivative, Cap Price	104
Average floor price	85
Average ceiling price	101.45
Year 2015 [Member] \| Q2 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	38,000
Derivative, Floor Price	80
Derivative, Cap Price	95.25
Average floor price	80
Average ceiling price	94.62
Year 2015 [Member] \| Q2 [Member] \| LLS [Member]	'
Derivative [Line Items]	'
Volume per Day	20,000
Derivative, Floor Price	85
Derivative, Cap Price	103
Average floor price	85
Average ceiling price	102.01
Year 2015 [Member] \| Q3 [Member] \| NYMEX [Member]	'
Derivative [Line Items]	'
Volume per Day	30,000
Derivative, Floor Price	80
Derivative, Cap Price	95.25
Average floor price	80
Average ceiling price	95.06
Year 2015 [Member] \| Q3 [Member] \| LLS [Member]	'
Derivative [Line Items]	'
Volume per Day	16,000
Derivative, Floor Price	85
Derivative, Cap Price	102.6
Average floor price	85
Average ceiling price	101.11

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities (Derivatives By Balance Sheet Location) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Derivative assets - current	$167	$19,477
Derivative assets - long-term	2,970	36
Derivative liabilities - current	-40,261	-2,842
Derivative liabilities - long-term	-16,013	-23,781
Total derivatives not designated as hedging instruments	-53,137	-7,110
Crude Oil Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative assets - current	167	19,477
Derivative assets - long-term	2,970	36
Derivative liabilities - current	-40,261	-2,659
Derivative liabilities - long-term	-16,013	-23,781
Deferred Premiums [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liabilities - current	$0	($183)

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Heirarchy Table) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Assets, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	$3,137	$19,513
Liabilities, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	-56,274	-26,440
Total	-53,137	-6,927
Quoted Prices in Active Markets (Level 1) [Member]	'	'
Assets, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	0	0
Liabilities, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	0	0
Total	0	0
Significant Other Observable Inputs (Level 2) [Member]	'	'
Assets, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	1,251	19,513
Liabilities, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	-54,534	-26,440
Total	-53,283	-6,927
Significant Unobservable Inputs (Level 3) [Member]	'	'
Assets, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	1,886	0
Liabilities, Fair Value Disclosure [Abstract]	'	'
Oil derivative contracts	-1,740	0
Total	$146	$0

Fair_Value_Measurements_Detail

Fair Value Measurements (Details Textuals) (USD $)	3 Months Ended		9 Months Ended
Fair Value Measurements (Details Textuals) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
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	'	$100,000	'	'
Other Asset Impairment Charges	0	0	0	17,515,000	'
Long-term Debt, Fair Value	2,921,000,000	'	2,921,000,000	'	2,957,000,000
Faustina Investment Impairment [Member]	'	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'	'
Other Asset Impairment Charges	'	'	'	$15,100,000	'

Commitments_and_Contingencies_

Commitments and Contingencies Commitments and Contingencies (Details) (USD $)	3 Months Ended	9 Months Ended	10 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013	Oct. 31, 2013
Loss Contingencies [Line Items]	'	'	'
Environmental Remediation Expense	$28	$98	'
Accrual for Environmental Loss Contingencies	31.3	31.3	'
Environmental Remediation Expense Incurred To Date	'	'	$85
Minimum [Member]	'	'	'
Loss Contingencies [Line Items]	'	'	'
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	33.00%	33.00%	'
Maximum [Member]	'	'	'
Loss Contingencies [Line Items]	'	'	'
Estimated Percentage of Environmental Remediation Expense Estimate to be Recovered Through Insurance Proceeds	67.00%	67.00%	'