Denbury (DNRWW) 10-Q 6 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document And Company Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	DNR
Current Fiscal Year End Date	--12-31
Entity Registrant Name	Denbury Resources Inc.
Entity Central Index Key	945,764
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		355,450,643

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 4,413	$ 23,153
Accrued production receivable	163,942	181,761
Trade and other receivables, net	98,857	156,955
Derivative assets	268,025	440,359
Deferred tax assets, net	8,060	0
Other current assets	15,085	10,452
Total current assets	558,382	812,680
Oil and natural gas properties (using full cost accounting)
Proved properties	9,994,968	9,782,337
Unevaluated properties	936,736	918,406
CO2 properties	1,172,262	1,162,538
Pipelines and plants	2,279,813	2,269,564
Other property and equipment	466,362	468,051
Less accumulated depletion, depreciation, amortization and impairment	(6,388,348)	(4,248,652)
Net property and equipment	8,461,793	10,352,244
Derivative assets	696	66,187
Goodwill	1,261,512	1,283,590
Other assets	212,920	213,101
Total assets	10,495,303	12,727,802
Current liabilities
Accounts payable and accrued liabilities	228,942	394,758
Oil and gas production payable	114,953	128,170
Derivative liabilities	641	0
Deferred tax liabilities	0	81,727
Current maturities of long-term debt	38,105	35,470
Total current liabilities	382,641	640,125
Long-term liabilities
Long-term debt, net of current portion	3,471,141	3,535,900
Asset retirement obligations	132,213	126,411
Deferred tax liabilities	2,084,208	2,694,842
Other liabilities	25,066	26,668
Total long-term liabilities	$ 5,712,628	$ 6,383,821
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; 414,023,232 and 411,779,911 shares issued, respectively	414	412
Paid-in capital in excess of par	3,225,728	3,230,418
Retained earnings	2,092,350	3,392,465
Accumulated other comprehensive loss	(174)	(209)
Treasury stock, at cost, 58,667,781 and 58,415,507 shares, respectively	(918,284)	(919,230)
Total stockholders' equity	4,400,034	5,703,856
Total liabilities and stockholders' equity	$ 10,495,303	$ 12,727,802

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2015	Dec. 31, 2014
Stockholders' equity
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	414,023,232	411,779,911
Treasury stock, shares	58,667,781	58,415,507

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues and other income
Oil, natural gas, and related product sales	$ 366,891	$ 657,029	$ 664,361	$ 1,280,875
CO2 and helium sales and transportation fees	7,152	11,822	14,124	22,583
Interest income and other income	2,651	3,269	5,858	10,406
Total revenues and other income	376,694	672,120	684,343	1,313,864
Expenses
Lease operating expenses	132,170	163,250	273,254	333,629
Marketing and plant operating expenses	14,215	18,149	25,900	34,935
CO2 and helium discovery and operating expenses	945	5,590	1,892	10,795
Taxes other than income	33,555	50,850	60,234	96,795
General and administrative expenses	37,947	38,952	84,227	82,645
Interest, net of amounts capitalized of $8,738, $5,795, $17,147, and $11,551, respectively	39,863	46,550	79,962	95,384
Depletion, depreciation, and amortization	147,940	148,164	297,898	289,294
Commodity derivatives expense (income)	48,926	174,771	(34,150)	251,440
Loss on early extinguishment of debt	0	113,908	0	113,908
Write-down of oil and natural gas properties	1,705,800	0	1,852,000	0
Total expenses	2,161,361	760,184	2,641,217	1,308,825
Income (loss) before income taxes	(1,784,667)	(88,064)	(1,956,874)	5,039
Income tax provision (benefit)	(636,168)	(32,864)	(700,629)	1,929
Net income (loss)	$ (1,148,499)	$ (55,200)	$ (1,256,245)	$ 3,110
Net income (loss) per common share
Basic	$ (3.28)	$ (0.16)	$ (3.59)	$ 0.01
Diluted	(3.28)	(0.16)	(3.59)	0.01
Dividends declared per common share	$ 0.0625	$ 0.0625	$ 0.1250	$ 0.125
Weighted average common shares outstanding
Basic	350,039	347,803	349,653	349,267
Diluted	350,039	347,803	349,653	351,566

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Expenses
Capitalized interest	$ 8,738	$ 5,795	$ 17,147	$ 11,551

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (1,148,499)	$ (55,200)	$ (1,256,245)	$ 3,110
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $10, $11, $21, and $24, respectively	18	17	35	32
Total other comprehensive income	18	17	35	32
Comprehensive income (loss)	$ (1,148,481)	$ (55,183)	$ (1,256,210)	$ 3,142

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other comprehensive income, net of income tax:
Tax for interest rate lock derivative contracts reclassified to income	$ 10	$ 11	$ 21	$ 24

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities
Net income (loss)	$ (1,256,245)	$ 3,110
Adjustments to reconcile net income (loss) to cash flow from operating activities
Depletion, depreciation, and amortization	297,898	289,294
Write-down of oil and natural gas properties	1,852,000	0
Deferred income taxes	(700,508)	1,611
Stock-based compensation	14,967	17,217
Commodity derivatives expense (income)	(34,150)	251,440
Receipt (payment) on settlements of commodity derivatives	272,616	(77,341)
Loss on early extinguishment of debt	0	113,908
Amortization of debt issuance costs and discounts	4,501	6,978
Other, net	(4,019)	(3,402)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	17,683	(25,236)
Trade and other receivables	57,865	12,921
Other current and long-term assets	(7,770)	(2,989)
Accounts payable and accrued liabilities	(71,892)	(36,178)
Oil and natural gas production payable	(13,217)	(2,033)
Other liabilities	(3,008)	(4,595)
Net cash provided by operating activities	426,721	544,705
Cash flows from investing activities
Oil and natural gas capital expenditures	(276,783)	(451,564)
Acquisitions of oil and natural gas properties	(20,374)	0
CO2 capital expenditures	(15,608)	(29,901)
Pipelines and plants capital expenditures	(20,349)	(34,530)
Purchases of other assets	(3,473)	(3,620)
Net proceeds from sales of oil and natural gas properties and equipment	131	1,736
Other	(56)	977
Net cash used in investing activities	(336,512)	(516,902)
Cash flows from financing activities
Bank repayments	(1,007,000)	(1,315,000)
Bank borrowings	962,000	1,420,000
Repayment of senior subordinated notes	0	(997,345)
Premium paid on repayment of senior subordinated notes	0	(101,342)
Proceeds from issuance of senior subordinated notes	0	1,250,000
Costs of debt financing	(1,632)	(17,551)
Common stock repurchase program	0	(211,356)
Cash dividends paid	(43,528)	(43,461)
Other	(18,789)	(11,889)
Net cash used in financing activities	(108,949)	(27,944)
Net decrease in cash and cash equivalents	(18,740)	(141)
Cash and cash equivalents at beginning of period	23,153	12,187
Cash and cash equivalents at end of period	$ 4,413	$ 12,046

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2015
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 an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations. 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, 2014 (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 June 30, 2015 , our consolidated results of operations for the three and six months ended June 30, 2015 and 2014 , and our consolidated cash flows for the six months ended June 30, 2015 and 2014 . 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 (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) 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 six months ended June 30, 2015 and 2014 , there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share . The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Basic weighted average common shares outstanding 350,039 347,803 349,653 349,267 Potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards — — — 2,299 Diluted weighted average common shares outstanding 350,039 347,803 349,653 351,566 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although all non-performance-based restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the six months ended June 30, 2014 , the nonvested restricted stock, stock options, SARs and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Stock options and SARs 9,949 4,949 10,228 4,601 Restricted stock and performance-based equity awards 2,241 1,337 2,595 679 Oil and Natural Gas Properties 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 a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as 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 CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. As a result of the precipitous decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, was $79.55 per Bbl for the first quarter of 2015 and $68.48 per Bbl for the second quarter of 2015. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $3.74 per Mcf for the second quarter of 2015. Because of the significant decrease in pricing during the fourth quarter of 2014 and its continued decline in the first and second quarters of 2015, we recognized full cost pool ceiling test write-downs of $1.7 billion and $0.2 billion during the three months ended June 30, 2015 and March 31, 2015, respectively. We currently expect that we will continue to record material write-downs in the third and fourth quarters of 2015 if oil and natural gas prices remain at or near late-July 2015 levels for the remainder of 2015, as the 12-month average price used in determining the full cost ceiling value would continue to decline during each rolling quarterly period in 2015, and also depending, in part, upon changes in proved oil and natural gas reserve volumes, future capital expenditures and operating costs. Goodwill We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of June 30, 2015 . Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of June 30, 2015 , we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on June 30, 2015 , NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the second quarter of 2015, nor have we recorded a goodwill impairment historically. Subsequent to June 30, 2015, our enterprise value declined at a rate in excess of the decline in NYMEX oil prices. If this relationship continues until we perform our next goodwill impairment assessment as of September 30, 2015, we could incur a partial or full impairment of our $1.3 billion goodwill balance, the amount of the impairment (if any) depending upon further changes in our enterprise value, oil and natural gas futures prices, and other key assumptions. Recent Accounting Pronouncements Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. The adoption of ASU 2015-03 is currently not expected to have a material effect on our consolidated financial statements, other than balance sheet reclassifications. Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect on our consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2016. However, in July 2015, the FASB affirmed their proposal to delay the effective date for one year and are awaiting final approval through an ASU, and early adoption will be permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 will have on our consolidated financial statements.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Note 2. Long-Term Debt The following long-term debt and capital lease obligations were outstanding as of the dates indicated: June 30, December 31, In thousands 2015 2014 Bank Credit Agreement $ 350,000 $ 395,000 6⅜% Senior Subordinated Notes due 2021 400,000 400,000 5½% Senior Subordinated Notes due 2022 1,250,000 1,250,000 4⅝% Senior Subordinated Notes due 2023 1,200,000 1,200,000 Other Subordinated Notes, including premium of $9 and $11, respectively 2,743 2,746 Pipeline financings 216,552 220,583 Capital lease obligations 89,951 103,041 Total 3,509,246 3,571,370 Less: current obligations (38,105 ) (35,470 ) Long-term debt and capital lease obligations $ 3,471,141 $ 3,535,900 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, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of certain of such notes are minor subsidiaries. Bank Credit Facility In December 2014 , we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the "Bank Credit Agreement"). The Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base of $3.0 billion and aggregate lender commitments of $1.6 billion . Loans under the Bank Credit Agreement mature in December 2019 . The weighted average interest rate on borrowings outstanding as of June 30, 2015 , under the Bank Credit Agreement was 1.5% . The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee ranging from 0.3% to 0.375% per annum. As of June 30, 2015 , we were in compliance with all debt covenants under the Bank Credit Agreement. Borrowing base redeterminations under our Bank Credit Agreement occur annually, and with the first such redetermination having been completed in early-May 2015, our next scheduled redetermination is set for May 2016. However, the lenders may, at their election, request one interim redetermination between annual scheduled redeterminations. In connection with the borrowing base redetermination completed in early-May 2015, we elected to maintain our aggregate lender commitments at $1.6 billion ; however, due to a reduction in oil prices used by our lenders in determining the borrowing base value of our proved reserves attributable to our oil and natural gas properties, our borrowing base was reduced from the previous level of $3.0 billion to $2.6 billion . Because we continue to maintain a significant cushion between our borrowing base and the aggregate lender commitments, and because we had significant availability with respect to our aggregate lender commitments as of June 30, 2015, this borrowing base reduction has no impact on our liquidity. In conjunction with the May 2015 redetermination, we also entered into the First Amendment to the Bank Credit Agreement (the "First Amendment"). This First Amendment restructures certain financial covenants in 2016, 2017, and 2018 in order to provide more flexibility in managing our balance sheet and managing the credit extended by our lenders if oil prices remain low over the next several years. The covenant changes included in the First Amendment were as follows: • In 2016 and 2017, suspend the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant of 4.25 to 1.0 and replace it with a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 2.5 to 1.0 during the same time period. Currently, only debt under our Bank Credit Agreement would be considered consolidated senior secured debt for purposes of this ratio. • Beginning in the first quarter of 2018, reinstate the ratio of consolidated total net debt to consolidated EBITDAX covenant utilizing an annualized EBITDAX amount for the first quarter of 2018 and building to a trailing four quarters by the end of 2018, with the maximum permitted ratios being 6.0 to 1.0 for the first quarter ended March 31, 2018, 5.5 to 1.0 for the second quarter ended June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ended September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ended March 31, 2019. • In 2016 and 2017, institute a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 2.25 to 1.0. The restructuring of covenants through the First Amendment was executed in consideration of a fee paid to the lenders. The First Amendment has no impact on the current ratio financial performance covenant, which will remain in place in 2015 and beyond. All of the above descriptions of financial covenants are qualified by the express language and defined terms contained in the Bank Credit Agreement. 2014 Issuance of 5½% Senior Subordinated Notes due 2022 In April 2014, we issued $1.25 billion of 5½% Senior Subordinated Notes due 2022 (the "5½% Notes"), which were sold at par. The net proceeds, after issuance costs, of $1.23 billion were used to repurchase or redeem our outstanding $996.3 million of 8¼% Senior Subordinated Notes due 2020 (the "8¼% Notes") (see 2014 Repurchase and Redemption of 8¼% Senior Subordinated Notes due 2020 below) and to pay down a portion of outstanding borrowings under our previous bank credit agreement. 2014 Repurchase and Redemption of 8¼% Senior Subordinated Notes due 2020 During the second quarter of 2014, we repurchased and redeemed the entire $996.3 million outstanding principal amount of our 8¼% Notes using a portion of the proceeds from the issuance of the 5½% Notes. We recognized a $113.9 million loss associated with the debt repurchases during the second quarter of 2014, which loss consists of both premium payments made to repurchase or redeem the 8¼% Notes and the elimination of unamortized debt issuance costs related to these notes. The loss is included in our Unaudited Condensed Consolidated Statements of Operations under the caption "Loss on early extinguishment of debt," and premium payments made to repurchase the notes are classified as a financing cash outflow on our Unaudited Condensed Consolidated Statements of Cash Flows under the caption "Premium paid on repayment of senior subordinated notes."

Income Taxes Income Taxes

Income Taxes Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Note 3. Income Taxes We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. As of June 30, 2015, we had $37.0 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company's utilization of certain deductions, including our net operating loss carryforwards, we recognized a tax valuation allowance of $30.5 million to reduce the carrying value of our deferred tax assets. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. Our effective tax rate for the three and six months ended June 30, 2015, was lower than our estimated statutory rate, primarily due to the impact of the tax valuation allowance discussed above, which reduced the net deferred tax benefit recognized.

Stockholders' Equity

Stockholders' Equity	6 Months Ended
	Jun. 30, 2015
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Note 4. Stockholders' Equity During the second quarter of 2015, we reduced the number of shares of our common stock reported as outstanding by 1,430,819 shares (approximately 0.4% of our outstanding shares at March 31, 2015). This reduction is the result of a correction to properly reflect the number of shares actually issued in the merger with Encore Acquisition Company ("Encore") in March 2010. The stock and cash consideration originally issued and paid in the Encore merger was valued at $3.0 billion , which would have been reduced by $22.1 million for this share correction. As a result, we have recorded adjustments in the accompanying June 30, 2015, Unaudited Condensed Consolidated Balance Sheet to reflect a decrease in consideration paid in the Encore merger through a reduction of "Goodwill" ( $22.1 million ), offset by a reduction in an equal amount of the Company's stockholders' equity ( $22.1 million ). We determined that this correction in outstanding shares (1) had no impact on net income (loss) for the second quarter of 2015, our estimated results of operations for the year ending December 31, 2015, or for any prior period, and (2) was not material to our consolidated balance sheet, statement of cash flows, or basic or diluted earnings per common share for the second quarter of 2015, or for any prior period, and therefore we recorded the cumulative effect of correcting these items during the three months ended June 30, 2015. Dividends In each of the first two quarters of both 2015 and 2014, the Company's Board of Directors declared quarterly cash dividends of $0.0625 per common share, or an annual rate of $0.25 per common share. Dividends totaling $43.5 million were paid to stockholders during the six months ended June 30, 2015 and 2014 . See Note 9 , Subsequent Event , for details regarding the dividend declared and to be paid in the third quarter of 2015 . Stock Repurchase Program Under our board-authorized share repurchase program, we repurchased 12.4 million shares of Denbury common stock for $200.4 million during the first quarter of 2014. In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty and to protect our financial position. Employee Stock Purchase Program We previously provided for an Employee Stock Purchase Plan (the "Plan") in which funds from eligible employees, together with Company contributions, were 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. The Plan was terminated, effective at the end of the offering period ended on March 31, 2015, as all of the previously authorized shares reserved for issuance under the Plan had been issued.

Commodity Derivative Contracts

Commodity Derivative Contracts	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts	Note 5. Commodity Derivative Contracts We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our 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 historically consisted of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. 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. For the past several years, we have generally hedged a substantial portion of our forecasted production over an approximately 18 month to two year future period, as we believed it was beneficial to protect our future cash flow at then-projected oil prices for those future periods. During the significant and rapid decline in oil prices in late-2014 and the first quarter of 2015, we deferred entering into new derivative contracts, and therefore currently have less of our production hedged and for a shorter future time period than we have generally had over the last several years. During the second quarter of 2015, we entered into new oil hedging positions covering the second and third quarters of 2016 in order to provide more certainty to our future cash flows in those quarters. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, 2015 , all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements. The following table summarizes our commodity derivative contracts as of June 30, 2015 , none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic: Months Index Price Volume (2) Contract Prices (1) Range (3) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2015 Enhanced Swaps (4) July – Sept NYMEX 10,000 $ 90.00 – 90.10 $ 90.02 $ 65.30 $ — $ — July – Sept LLS 16,000 93.20 – 94.00 93.65 68.00 — — Oct – Dec NYMEX 12,000 91.15 – 94.00 92.42 68.00 — — Oct – Dec LLS 8,000 93.80 – 96.50 94.94 68.00 — — 2015 Collars July – Sept NYMEX 28,000 $ 80.00 – 95.25 $ — $ — $ 80.00 $ 95.05 July – Sept LLS 4,000 85.00 – 100.00 — — 85.00 99.50 2015 Three-Way Collars (5) Oct – Dec NYMEX 10,000 $ 85.00 – 102.00 $ — $ 68.00 $ 85.00 $ 99.00 Oct – Dec LLS 8,000 88.00 – 104.25 — 68.00 88.00 100.99 2016 Enhanced Swaps (4) Jan – Mar NYMEX 12,000 $ 90.65 – 93.35 $ 92.43 $ 68.00 $ — $ — Jan – Mar LLS 8,000 93.70 – 95.45 94.81 68.50 — — Apr – June NYMEX 2,000 90.35 – 90.35 90.35 68.00 — — Apr – June LLS 6,000 93.30 – 93.50 93.38 70.00 — — 2016 Fixed-Price Swaps Apr – June NYMEX 11,500 $ 60.30 – 63.75 $ 61.84 $ — $ — $ — Apr – June LLS 3,500 64.20 – 66.15 64.99 — — — 2016 Three-Way Collars (5) Jan – Mar NYMEX 10,000 $ 85.00 – 101.25 $ — $ 68.00 $ 85.00 $ 99.85 Jan – Mar LLS 6,000 88.00 – 103.15 — 68.00 88.00 102.10 Apr – June NYMEX 2,000 85.00 – 95.50 — 68.00 85.00 95.50 Apr – June LLS 2,000 88.00 – 98.25 — 70.00 88.00 98.25 2016 Collars Apr – June NYMEX 5,000 $ 55.00 – 72.25 $ — $ — $ 55.00 $ 71.01 Apr – June LLS 2,000 58.00 – 73.00 — — 58.00 73.00 July – Sept NYMEX 4,500 55.00 – 72.65 — — 55.00 71.22 July – Sept LLS 3,000 58.00 – 74.30 — — 58.00 73.85 Natural Gas Contracts: 2015 Collars July – Dec NYMEX 8,000 $ 4.00 – 4.53 $ — $ — $ 4.00 $ 4.51 (1) Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively. (2) Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively. (3) Ranges presented for fixed-price swaps and enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (4) An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes. (5) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 6. Fair Value Measurements The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the "exit price"). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At June 30, 2015 , instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $0.8 million in the fair value of these instruments as of June 30, 2015 . 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 in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total June 30, 2015 Assets: Oil and natural gas derivative contracts – current $ — $ 155,972 $ 112,053 $ 268,025 Oil and natural gas derivative contracts – long-term — 391 305 696 Total Assets $ — $ 156,363 $ 112,358 $ 268,721 Liabilities: Oil and natural gas derivative contracts – current $ — $ 641 $ — $ 641 Oil and natural gas derivative contracts – long-term — — — — Total Liabilities $ — $ 641 $ — $ 641 December 31, 2014 Assets: Oil and natural gas derivative contracts – current $ — $ 283,238 $ 157,121 $ 440,359 Oil and natural gas derivative contracts – long-term — 34,862 31,325 66,187 Total Assets $ — $ 318,100 $ 188,446 $ 506,546 Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in "Commodity derivatives expense (income)" in the accompanying Unaudited Condensed Consolidated Statements of Operations. Level 3 Fair Value Measurements The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and six months ended June 30, 2015 and 2014 : Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Fair value of Level 3 instruments, beginning of period $ 165,015 $ (6,097 ) $ 188,446 $ 6,709 Fair value adjustments on commodity derivatives (7,302 ) (33,019 ) 17,783 (45,825 ) Receipt on settlements of commodity derivatives (45,355 ) — (93,871 ) — Fair value of Level 3 instruments, end of period $ 112,358 $ (39,116 ) $ 112,358 $ (39,116 ) The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date $ (4,325 ) $ (33,019 ) $ 14,142 $ (45,825 ) We utilize an income approach to value our Level 3 enhanced swaps, costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts: Fair Value at Valuation Technique Unobservable Input Range Oil derivative contracts $ 112,358 Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2015 16.0% - 33.6% Other Fair Value Measurements The carrying value of loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine fair value of our fixed-rate long-term 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 debt as of June 30, 2015 and December 31, 2014 , excluding pipeline financing and capital lease obligations, was $2,867.7 million and $2,938.6 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	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 7. Commitments and Contingencies We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. 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. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated. 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. We completed our remediation efforts with respect to such release during the fourth quarter of 2013; however, we continue to monitor the impacted area to confirm the effectiveness of the remediation efforts. Virtually all of our total cost estimate of $130.8 million has been incurred. We maintain insurance policies to cover certain costs, damages and claims related to releases of well fluids and remediation. We received a $25.0 million cost reimbursement in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess insurance coverage. We have not reached any agreement with our remaining carriers as to further reimbursements, but given our belief that under our policies we are entitled to reimbursement of between approximately one-third and two-thirds of our total costs, we have filed suit to pursue further reimbursements, the ultimate outcome of which cannot be predicted. In March 2015, Evolution Petroleum Company ("Evolution"), the parent of the entity which sold Denbury Onshore, LLC ("Denbury Onshore") its original interest in Delhi Field, filed an amended petition in a lawsuit which has been pending in the Texas district court in Houston since December 2013. Originally, that lawsuit involved ongoing disputes between Denbury Onshore and Evolution regarding the terms of the purchase documents under which Denbury Onshore bought its original Delhi Field interest, including disputes regarding allocation of costs in determining "payout" as defined in the agreements, and the extent and terms of assignment of reversionary interests in the Unit back to Evolution following payout, along with related contractual terms. The amended petition added allegations of negligence and gross negligence against Denbury Onshore in connection with the June 2013 Delhi Field release, and for the first time estimated its damages attributable to its allegations in the case as exceeding $200 million . The amended petition also adds a claim for unspecified punitive damages. There has only been limited discovery in the case to date, and Evolution has not specified the basis for the amount of its claimed damages estimate. The case is currently set for trial in April 2016. We believe Evolution's claims with respect to this matter are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.

Additional Balance Sheet Detail

Additional Balance Sheet Details	6 Months Ended
	Jun. 30, 2015
Disclosure Text Block [Abstract]
Supplemental Balance Sheet Disclosures	Note 8. Additional Balance Sheet Details Trade Accounts Receivable, net June 30, December 31, In thousands 2015 2014 Trade accounts receivable, net $ 43,291 $ 45,407 Commodity derivatives settlement receivables 38,896 59,755 Federal income tax receivable, net — 37,652 Other receivables 16,670 14,141 Total $ 98,857 $ 156,955 Accounts Payable and Accrued Liabilities June 30, December 31, In thousands 2015 2014 Accrued interest $ 48,802 $ 48,255 Accrued lease operating expenses 36,029 56,798 Accrued compensation 33,702 62,513 Accounts payable 31,805 64,604 Taxes payable 30,654 39,816 Accrued exploration and development costs 19,590 90,939 Other 28,360 31,833 Total $ 228,942 $ 394,758

Subsequent Event

Subsequent Event	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Event	Note 9. Subsequent Event Dividend Declaration On July 28, 2015, the Board of Directors declared a dividend of $0.0625 per share on our outstanding common stock, payable on September 29, 2015, to stockholders of record at the close of business on August 25, 2015.

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations.
Interim Financial Statements - Basis of Accounting, Policy	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, 2014 (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.
Interim Financial Statements - Use of Estimates	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 June 30, 2015 , our consolidated results of operations for the three and six months ended June 30, 2015 and 2014 , and our consolidated cash flows for the six months ended June 30, 2015 and 2014 .
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.
Net Income (Loss) per Common Share	Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) 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 six months ended June 30, 2015 and 2014 , there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share . The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Basic weighted average common shares outstanding 350,039 347,803 349,653 349,267 Potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards — — — 2,299 Diluted weighted average common shares outstanding 350,039 347,803 349,653 351,566 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although all non-performance-based restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the six months ended June 30, 2014 , the nonvested restricted stock, stock options, SARs and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, the purchase price that the grantee will pay in the future for stock options, and any estimated future tax consequences recognized directly in equity. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Stock options and SARs 9,949 4,949 10,228 4,601 Restricted stock and performance-based equity awards 2,241 1,337 2,595 679
Oil and Natural Gas Properties Policy	Oil and Natural Gas Properties 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 a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO 2 reserves nor those related to the cost of constructing CO 2 pipelines, as 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 CO 2 costs related to CO 2 reserves and CO 2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. As a result of the precipitous decline in NYMEX oil prices since the fourth quarter of 2014, the rolling first-day-of-the-month average oil price for the preceding 12 months, after adjustments for market differentials by field, was $79.55 per Bbl for the first quarter of 2015 and $68.48 per Bbl for the second quarter of 2015. In addition, the first-day-of-the-month average natural gas price for the preceding 12 months, after adjustments for market differentials by field, was $3.95 per Mcf for the first quarter of 2015 and $3.74 per Mcf for the second quarter of 2015. Because of the significant decrease in pricing during the fourth quarter of 2014 and its continued decline in the first and second quarters of 2015, we recognized full cost pool ceiling test write-downs of $1.7 billion and $0.2 billion during the three months ended June 30, 2015 and March 31, 2015, respectively. We currently expect that we will continue to record material write-downs in the third and fourth quarters of 2015 if oil and natural gas prices remain at or near late-July 2015 levels for the remainder of 2015, as the 12-month average price used in determining the full cost ceiling value would continue to decline during each rolling quarterly period in 2015, and also depending, in part, upon changes in proved oil and natural gas reserve volumes, future capital expenditures and operating costs.
Goodwill Policy	Goodwill We test goodwill for impairment annually during the fourth quarter; however, as a result of the relationship between our market capitalization and our book value of stockholders' equity and the sustained decrease in our share price, we also performed a goodwill impairment assessment as of June 30, 2015 . Because our enterprise value (combined market capitalization plus a control premium of 10% and the fair value of our long-term debt) was below the combined book value of our stockholders' equity and long-term debt as of June 30, 2015 , we were required to proceed to step two of the goodwill impairment test. Oil and natural gas reserves, which represent the most significant assets requiring valuation, were estimated using the expected present value of future cash flows method based on June 30, 2015 , NYMEX oil and natural gas futures prices for the next five years, adjusted for current price differentials. Consistent with the results of our fourth quarter 2014 goodwill analysis, the implied fair value of goodwill calculated in this quantitative assessment exceeded the corresponding book value of goodwill. Therefore, we did not record any goodwill impairment during the second quarter of 2015, nor have we recorded a goodwill impairment historically. Subsequent to June 30, 2015, our enterprise value declined at a rate in excess of the decline in NYMEX oil prices. If this relationship continues until we perform our next goodwill impairment assessment as of September 30, 2015, we could incur a partial or full impairment of our $1.3 billion goodwill balance, the amount of the impairment (if any) depending upon further changes in our enterprise value, oil and natural gas futures prices, and other key assumptions.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction of the carrying amount of that debt in the balance sheet, consistent with the presentation of debt discounts. The amendments in this ASU are effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, and early adoption is permitted. Entities will be required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. The adoption of ASU 2015-03 is currently not expected to have a material effect on our consolidated financial statements, other than balance sheet reclassifications. Consolidation. In February 2015, the FASB issued ASU 2015-02, Consolidation: Amendments to the Consolidation Analysis ("ASU 2015-02"). ASU 2015-02 amends the guidance for consolidation of certain types of legal entities. Under the ASU, all reporting entities are required to evaluate whether they should consolidate certain legal entities under the revised consolidation model. The amendment focuses on limited partnerships and similar legal entities, fees paid to a decision maker or a service provider as a variable interest, fee arrangements and related party effects on the primary beneficiary determination and certain investment funds. The amendments in this ASU are effective for annual periods beginning after December 15, 2015, and interim periods within those years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the beginning of the fiscal year of adoption. The adoption of ASU 2015-02 is currently not expected to have a material effect on our consolidated financial statements. Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. The amendments in this ASU are currently effective for reporting periods beginning after December 15, 2016. However, in July 2015, the FASB affirmed their proposal to delay the effective date for one year and are awaiting final approval through an ASU, and early adoption will be permitted. Entities can transition to the standard either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Management is currently assessing the impact the adoption of ASU 2014-09 will have on our consolidated financial statements.
Commodity Derivative Contracts	We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under "Commodity derivatives expense (income)" in our 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 historically consisted of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. 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. For the past several years, we have generally hedged a substantial portion of our forecasted production over an approximately 18 month to two year future period, as we believed it was beneficial to protect our future cash flow at then-projected oil prices for those future periods. During the significant and rapid decline in oil prices in late-2014 and the first quarter of 2015, we deferred entering into new derivative contracts, and therefore currently have less of our production hedged and for a shorter future time period than we have generally had over the last several years. During the second quarter of 2015, we entered into new oil hedging positions covering the second and third quarters of 2016 in order to provide more certainty to our future cash flows in those quarters. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, 2015 , 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	The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the "exit price"). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: • Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The fixed-price swap features of our enhanced swaps are valued using a discounted cash flow model based upon forward commodity price curves. Our costless collars and the sold put features of our enhanced oil swaps and three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At June 30, 2015 , instruments in this category include non-exchange-traded enhanced swaps, costless collars and three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for enhanced swaps, costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $0.8 million in the fair value of these instruments as of June 30, 2015 . 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)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Weighted average shares used in the basic and diluted net income (loss) per common share	The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Basic weighted average common shares outstanding 350,039 347,803 349,653 349,267 Potentially dilutive securities Restricted stock, stock options, SARs and performance-based equity awards — — — 2,299 Diluted weighted average common shares outstanding 350,039 347,803 349,653 351,566
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive: Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Stock options and SARs 9,949 4,949 10,228 4,601 Restricted stock and performance-based equity awards 2,241 1,337 2,595 679

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Components of Long-Term Debt	The following long-term debt and capital lease obligations were outstanding as of the dates indicated: June 30, December 31, In thousands 2015 2014 Bank Credit Agreement $ 350,000 $ 395,000 6⅜% Senior Subordinated Notes due 2021 400,000 400,000 5½% Senior Subordinated Notes due 2022 1,250,000 1,250,000 4⅝% Senior Subordinated Notes due 2023 1,200,000 1,200,000 Other Subordinated Notes, including premium of $9 and $11, respectively 2,743 2,746 Pipeline financings 216,552 220,583 Capital lease obligations 89,951 103,041 Total 3,509,246 3,571,370 Less: current obligations (38,105 ) (35,470 ) Long-term debt and capital lease obligations $ 3,471,141 $ 3,535,900

Commodity Derivative Contracts

Commodity Derivative Contracts (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative contracts not classified as hedging instruments	The following table summarizes our commodity derivative contracts as of June 30, 2015 , none of which are classified as hedging instruments in accordance with the Financial Accounting Standards Board Codification ("FASC") Derivatives and Hedging topic: Months Index Price Volume (2) Contract Prices (1) Range (3) Weighted Average Price Swap Sold Put Floor Ceiling Oil Contracts: 2015 Enhanced Swaps (4) July – Sept NYMEX 10,000 $ 90.00 – 90.10 $ 90.02 $ 65.30 $ — $ — July – Sept LLS 16,000 93.20 – 94.00 93.65 68.00 — — Oct – Dec NYMEX 12,000 91.15 – 94.00 92.42 68.00 — — Oct – Dec LLS 8,000 93.80 – 96.50 94.94 68.00 — — 2015 Collars July – Sept NYMEX 28,000 $ 80.00 – 95.25 $ — $ — $ 80.00 $ 95.05 July – Sept LLS 4,000 85.00 – 100.00 — — 85.00 99.50 2015 Three-Way Collars (5) Oct – Dec NYMEX 10,000 $ 85.00 – 102.00 $ — $ 68.00 $ 85.00 $ 99.00 Oct – Dec LLS 8,000 88.00 – 104.25 — 68.00 88.00 100.99 2016 Enhanced Swaps (4) Jan – Mar NYMEX 12,000 $ 90.65 – 93.35 $ 92.43 $ 68.00 $ — $ — Jan – Mar LLS 8,000 93.70 – 95.45 94.81 68.50 — — Apr – June NYMEX 2,000 90.35 – 90.35 90.35 68.00 — — Apr – June LLS 6,000 93.30 – 93.50 93.38 70.00 — — 2016 Fixed-Price Swaps Apr – June NYMEX 11,500 $ 60.30 – 63.75 $ 61.84 $ — $ — $ — Apr – June LLS 3,500 64.20 – 66.15 64.99 — — — 2016 Three-Way Collars (5) Jan – Mar NYMEX 10,000 $ 85.00 – 101.25 $ — $ 68.00 $ 85.00 $ 99.85 Jan – Mar LLS 6,000 88.00 – 103.15 — 68.00 88.00 102.10 Apr – June NYMEX 2,000 85.00 – 95.50 — 68.00 85.00 95.50 Apr – June LLS 2,000 88.00 – 98.25 — 70.00 88.00 98.25 2016 Collars Apr – June NYMEX 5,000 $ 55.00 – 72.25 $ — $ — $ 55.00 $ 71.01 Apr – June LLS 2,000 58.00 – 73.00 — — 58.00 73.00 July – Sept NYMEX 4,500 55.00 – 72.65 — — 55.00 71.22 July – Sept LLS 3,000 58.00 – 74.30 — — 58.00 73.85 Natural Gas Contracts: 2015 Collars July – Dec NYMEX 8,000 $ 4.00 – 4.53 $ — $ — $ 4.00 $ 4.51 (1) Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively. (2) Contract volumes are stated in Bbls/d and MMBtus/d for oil and natural gas contracts, respectively. (3) Ranges presented for fixed-price swaps and enhanced swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (4) An enhanced swap is a fixed-price swap contract combined with a sold put feature (at a lower price) with the same counterparty. The value associated with the sold put is used to increase or enhance the fixed price of the swap. At the contract settlement date, (1) if the index price is higher than the swap price, we pay the counterparty the difference between the index price and swap price for the contracted volumes, (2) if the index price is lower than the swap price but at or above the sold put price, the counterparty pays us the difference between the index price and the swap price for the contracted volumes and (3) if the index price is lower than the sold put price, the counterparty pays us the difference between the swap price and the sold put price for the contracted volumes. (5) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
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 in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total June 30, 2015 Assets: Oil and natural gas derivative contracts – current $ — $ 155,972 $ 112,053 $ 268,025 Oil and natural gas derivative contracts – long-term — 391 305 696 Total Assets $ — $ 156,363 $ 112,358 $ 268,721 Liabilities: Oil and natural gas derivative contracts – current $ — $ 641 $ — $ 641 Oil and natural gas derivative contracts – long-term — — — — Total Liabilities $ — $ 641 $ — $ 641 December 31, 2014 Assets: Oil and natural gas derivative contracts – current $ — $ 283,238 $ 157,121 $ 440,359 Oil and natural gas derivative contracts – long-term — 34,862 31,325 66,187 Total Assets $ — $ 318,100 $ 188,446 $ 506,546
Changes in fair value of Level 3 assets and liabilities	The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and six months ended June 30, 2015 and 2014 : Three Months Ended Six Months Ended June 30, June 30, In thousands 2015 2014 2015 2014 Fair value of Level 3 instruments, beginning of period $ 165,015 $ (6,097 ) $ 188,446 $ 6,709 Fair value adjustments on commodity derivatives (7,302 ) (33,019 ) 17,783 (45,825 ) Receipt on settlements of commodity derivatives (45,355 ) — (93,871 ) — Fair value of Level 3 instruments, end of period $ 112,358 $ (39,116 ) $ 112,358 $ (39,116 ) The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date $ (4,325 ) $ (33,019 ) $ 14,142 $ (45,825 )
Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3)	The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts: Fair Value at Valuation Technique Unobservable Input Range Oil derivative contracts $ 112,358 Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2015 16.0% - 33.6%

Additional Balance Sheet Deta23

Additional Balance Sheet Details (Tables)	6 Months Ended
	Jun. 30, 2015
Table Text Block [Abstract]
Trade Accounts Receivable, net	Trade Accounts Receivable, net June 30, December 31, In thousands 2015 2014 Trade accounts receivable, net $ 43,291 $ 45,407 Commodity derivatives settlement receivables 38,896 59,755 Federal income tax receivable, net — 37,652 Other receivables 16,670 14,141 Total $ 98,857 $ 156,955
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities June 30, December 31, In thousands 2015 2014 Accrued interest $ 48,802 $ 48,255 Accrued lease operating expenses 36,029 56,798 Accrued compensation 33,702 62,513 Accounts payable 31,805 64,604 Taxes payable 30,654 39,816 Accrued exploration and development costs 19,590 90,939 Other 28,360 31,833 Total $ 228,942 $ 394,758

Basis of Presentation (Reconcil

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Weighted average shares used in the basic and diluted net income per common share
Basic weighted average common shares outstanding	350,039	347,803	349,653	349,267
Potentially dilutive securities
Restricted stock, stock options, SARs and performance-based equity awards	0	0	0	2,299
Diluted weighted average common shares outstanding	350,039	347,803	349,653	351,566

Basis of Presentation Antidilut

Basis of Presentation Antidilutive Securities (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Stock Options and SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	9,949	4,949	10,228	4,601
Restricted stock and performance-based equity awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,241	1,337	2,595	679

Basis of Presentation (Details

Basis of Presentation (Details Textuals) $ in Thousands	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)$ / Mcf$ / Barrel	Mar. 31, 2015$ / Mcf$ / Barrel	Dec. 31, 2014USD ($)
Accounting Policies [Abstract]
Write-down of oil and natural gas properties	$ 1,705,800	$ 200,000	$ 0	$ 1,852,000	$ 0
Goodwill	$ 1,261,512			$ 1,261,512		$ 1,261,512		$ 1,283,590
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Oil and Natural Gas Prices | $ / Barrel						68.48	79.55
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Oil and Natural Gas Prices | $ / Mcf						3.74	3.95

Long-Term Debt (Components of L

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Bank Credit Agreement	$ 350,000	$ 395,000
Pipeline financings	216,552	220,583
Capital lease obligations	89,951	103,041
Total	3,509,246	3,571,370
Less current obligations	(38,105)	(35,470)
Long-term debt and capital lease obligations	3,471,141	3,535,900
6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Senior Subordinated Notes	$ 400,000	400,000
Debt Instrument, Interest Rate, Stated Percentage	6.375%
5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Senior Subordinated Notes	$ 1,250,000	1,250,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%
4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Senior Subordinated Notes	$ 1,200,000	1,200,000
Debt Instrument, Interest Rate, Stated Percentage	4.625%
Other Subordinated Notes
Debt Instrument [Line Items]
Senior Subordinated Notes	$ 2,743	2,746
Including premium of	$ 9	$ 11

Long-Term Debt (Details Textual

Long-Term Debt (Details Textuals)	Apr. 30, 2014USD ($)	Jun. 30, 2015	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	May. 01, 2015USD ($)	Dec. 31, 2014USD ($)	Apr. 01, 2014USD ($)
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%	100.00%		100.00%
Gains (Losses) on Extinguishment of Debt			$ 0	$ 113,908,000	$ 0	$ 113,908,000
Proceeds from issuance of senior subordinated notes					$ 0	1,250,000,000
$1.6 Billion Revolving Credit Facility [Abstract]
Line of Credit, Borrowing Base							$ 2,600,000,000	$ 3,000,000,000
Line of Credit Facility, Current Borrowing Capacity							$ 1,600,000,000	$ 1,600,000,000
Weighted average interest rate on Bank Credit Facility					1.50%
Total Net Debt to EBITDAX Requirement			4.25
Year 2,016
$1.6 Billion Revolving Credit Facility [Abstract]
Senior Secured Debt to EBITDAX		2.5
EBITDAX to Consolidated Interest		2.25
Year 2,017
$1.6 Billion Revolving Credit Facility [Abstract]
Senior Secured Debt to EBITDAX		2.5
EBITDAX to Consolidated Interest		2.25
Q1 | Year 2018
$1.6 Billion Revolving Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement		6
Q1 | Year 2019
$1.6 Billion Revolving Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement		4.25
Q2 | Year 2018
$1.6 Billion Revolving Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement		5.5
Q3 | Year 2018
$1.6 Billion Revolving Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement		5
Q4 | Year 2018
$1.6 Billion Revolving Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement		5
Minimum
$1.6 Billion Revolving Credit Facility [Abstract]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					0.30%
Maximum
$1.6 Billion Revolving Credit Facility [Abstract]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					0.375%
5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Proceeds from issuance of senior subordinated notes	$ 1,230,000,000
Debt Instrument, Face Amount									$ 1,250,000,000
8 1/4% Senior Subordinated Notes due 2020
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount				$ 996,300,000		$ 996,300,000

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details) $ in Millions	Jun. 30, 2015USD ($)
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Valuation Allowance	$ 30.5
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	$ 37

Stockholders' Equity (Details T

Stockholders' Equity (Details Textuals) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended				6 Months Ended
	Mar. 31, 2010	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Percentage of shares outstanding at March 31, 2015			0.40%
Consideration issued	$ 3,000,000
Dividends declared per common share		$ 0.0625	$ 0.0625	$ 0.0625	$ 0.0625	$ 0.1250	$ 0.125
Annualized common stock cash dividend per share						$ 0.25	$ 0.25
Cash dividend payment						$ 43,528	$ 43,461
Treasury Stock, Shares, Acquired					12,400,000
Treasury Stock, Value, Acquired, Cost Method					$ 200,400
Adjustments for Error Correction
Decrease in number of shares		1,430,819
Share correction amount		$ 22,100				$ 22,100
Reduction in goodwill		22,100
Reduction in stockholders' equity		$ 22,100

Commodity Derivative Contract31

Commodity Derivative Contracts (Details) - Jun. 30, 2015	MMBTU / dbbl / d$ / MMBTU$ / Barrel
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	10,000
Weighted average swap price	90.02
Weighted average sold put price	65.30
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	90
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	90.10
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	16,000
Weighted average swap price	93.65
Weighted average sold put price	68
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.20
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q3 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	94
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	12,000
Weighted average swap price	92.42
Weighted average sold put price	68
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	91.15
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	94
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	8,000
Weighted average swap price	94.94
Weighted average sold put price	68
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.80
Enhanced Swaps | Crude Oil Contracts | Year 2015 | Q4 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	96.50
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	12,000
Weighted average swap price	92.43
Weighted average sold put price	68
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	90.65
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.35
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	8,000
Weighted average swap price	94.81
Weighted average sold put price	68.50
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.70
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q1 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	95.45
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	2,000
Weighted average swap price	90.35
Weighted average sold put price	68
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	90.35
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	90.35
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	6,000
Weighted average swap price	93.38
Weighted average sold put price	70
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.30
Enhanced Swaps | Crude Oil Contracts | Year 2016 | Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	93.50
Collar | Crude Oil Contracts | Year 2015 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	28,000
Derivative, Floor Price	80
Derivative, Cap Price	95.25
Weighted average floor price	80
Weighted average ceiling price	95.05
Collar | Crude Oil Contracts | Year 2015 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	4,000
Derivative, Floor Price	85
Derivative, Cap Price	100
Weighted average floor price	85
Weighted average ceiling price	99.50
Collar | Crude Oil Contracts | Year 2016 | Q2 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	5,000
Derivative, Floor Price	55
Derivative, Cap Price	72.25
Weighted average floor price	55
Weighted average ceiling price	71.01
Collar | Crude Oil Contracts | Year 2016 | Q2 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	2,000
Derivative, Floor Price	58
Derivative, Cap Price	73
Weighted average floor price	58
Weighted average ceiling price	73
Collar | Crude Oil Contracts | Year 2016 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	4,500
Derivative, Floor Price	55
Derivative, Cap Price	72.65
Weighted average floor price	55
Weighted average ceiling price	71.22
Collar | Crude Oil Contracts | Year 2016 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	3,000
Derivative, Floor Price	58
Derivative, Cap Price	74.30
Weighted average floor price	58
Weighted average ceiling price	73.85
Collar | Natural Gas Contracts | Year 2015 | NYMEX
Derivative [Line Items]
Volume per Day | MMBTU / d	8,000
Derivative, Floor Price | $ / MMBTU	4
Derivative, Cap Price | $ / MMBTU	4.53
Weighted average floor price | $ / MMBTU	4
Weighted average ceiling price | $ / MMBTU	4.51
Three-way Collar | Crude Oil Contracts | Year 2015 | Q4 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	10,000
Derivative, Floor Price	85
Derivative, Cap Price	102
Weighted average sold put price	68
Weighted average floor price	85
Weighted average ceiling price	99
Three-way Collar | Crude Oil Contracts | Year 2015 | Q4 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	8,000
Derivative, Floor Price	88
Derivative, Cap Price	104.25
Weighted average sold put price	68
Weighted average floor price	88
Weighted average ceiling price	100.99
Three-way Collar | Crude Oil Contracts | Year 2016 | Q1 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	10,000
Derivative, Floor Price	85
Derivative, Cap Price	101.25
Weighted average sold put price	68
Weighted average floor price	85
Weighted average ceiling price	99.85
Three-way Collar | Crude Oil Contracts | Year 2016 | Q1 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	6,000
Derivative, Floor Price	88
Derivative, Cap Price	103.15
Weighted average sold put price	68
Weighted average floor price	88
Weighted average ceiling price	102.10
Three-way Collar | Crude Oil Contracts | Year 2016 | Q2 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	2,000
Derivative, Floor Price	85
Derivative, Cap Price	95.50
Weighted average sold put price	68
Weighted average floor price	85
Weighted average ceiling price	95.50
Three-way Collar | Crude Oil Contracts | Year 2016 | Q2 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	2,000
Derivative, Floor Price	88
Derivative, Cap Price	98.25
Weighted average sold put price	70
Weighted average floor price	88
Weighted average ceiling price	98.25
Swap | Crude Oil Contracts | Year 2016 | Q2 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	11,500
Weighted average swap price	61.84
Swap | Crude Oil Contracts | Year 2016 | Q2 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	60.30
Swap | Crude Oil Contracts | Year 2016 | Q2 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	63.75
Swap | Crude Oil Contracts | Year 2016 | Q2 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	3,500
Weighted average swap price	64.99
Swap | Crude Oil Contracts | Year 2016 | Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	64.20
Swap | Crude Oil Contracts | Year 2016 | Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	66.15

Commodity Derivative Contract32

Commodity Derivative Contracts (Details Textuals)	6 Months Ended
	Jun. 30, 2015
Minimum
Derivative [Line Items]
Derivative, Average Remaining Maturity	18 months
Maximum
Derivative [Line Items]
Derivative, Average Remaining Maturity	2 years

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Current	$ 268,025	$ 440,359
Derivative Asset, Long-term	696	66,187
Total Derivative Assets	268,721	506,546
Derivative Liability, Current	641
Derivative Liability, Noncurrent	0
Total Derivative Liabilities	641
Quoted Prices in Active Markets (Level 1)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Current	0	0
Derivative Asset, Long-term	0	0
Total Derivative Assets	0	0
Derivative Liability, Current	0
Derivative Liability, Noncurrent	0
Total Derivative Liabilities	0
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Current	155,972	283,238
Derivative Asset, Long-term	391	34,862
Total Derivative Assets	156,363	318,100
Derivative Liability, Current	641
Derivative Liability, Noncurrent	0
Total Derivative Liabilities	641
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Current	112,053	157,121
Derivative Asset, Long-term	305	31,325
Total Derivative Assets	112,358	$ 188,446
Derivative Liability, Current	0
Derivative Liability, Noncurrent	0
Total Derivative Liabilities	$ 0

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of period	$ 165,015	$ (6,097)	$ 188,446	$ 6,709
Fair value adjustments on commodity derivatives	(7,302)	(33,019)	17,783	(45,825)
Receipt on settlements of commodity derivatives	(45,355)	0	(93,871)	0
Fair value of Level 3 instruments, end of period	112,358	(39,116)	112,358	(39,116)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date	$ (4,325)	$ (33,019)	$ 14,142	$ (45,825)

Fair Value Measurements (Leve35

Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 112,358	$ 165,015	$ 188,446	$ (39,116)	$ (6,097)	$ 6,709
Income Approach Valuation Technique
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 112,358
Income Approach Valuation Technique | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Rate	16.00%
Income Approach Valuation Technique | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Rate	33.60%

Fair Value Measurements (Detail

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs	$ 0.8
Debt, Fair Value	$ 2,867.7	$ 2,938.6

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($)	1 Months Ended	4 Months Ended	25 Months Ended
	Oct. 31, 2014	Jun. 30, 2015	Jun. 30, 2015
Loss Contingencies [Line Items]
Environmental remediation expense			$ 130,800,000
Gross proceeds from insurance settlement, operating activities	$ 25,000,000
Minimum
Loss Contingencies [Line Items]
Estimated percentage of environmental remediation expense estimate to be recovered through insurance proceeds		33.33333%	33.33333%
Loss Contingency, Damages Sought, Value		$ 200,000,000
Maximum
Loss Contingencies [Line Items]
Estimated percentage of environmental remediation expense estimate to be recovered through insurance proceeds		66.66667%	66.66667%

Additional Balance Sheet Deta38

Additional Balance Sheet Details (Trade Accounts Receivable, net) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Receivables [Abstract]
Trade accounts receivable, net	$ 43,291	$ 45,407
Commodity derivatives settlement receivables	38,896	59,755
Federal income tax receivable, net	0	37,652
Other receivables	16,670	14,141
Total	$ 98,857	$ 156,955

Additional Balance Sheet Deta39

Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounts Payable and Accrued Liabilities, Current [Abstract]
Accrued interest	$ 48,802	$ 48,255
Accrued lease operating expenses	36,029	56,798
Accrued compensation	33,702	62,513
Accounts payable	31,805	64,604
Taxes payable	30,654	39,816
Accrued exploration and development costs	19,590	90,939
Other	28,360	31,833
Total	$ 228,942	$ 394,758

Subsequent Event (Details Textu

Subsequent Event (Details Textuals)	Jul. 28, 2015$ / shares
Subsequent Event
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.0625