DNR Denbury Resources Inc

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(1)

Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of June 30, 2016 include $51.0 million of future interest payable related to this balance that is due within the next twelve months. See 2016 Senior Subordinated Notes Exchange below for further discussion.

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•	for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio);

•	for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0;

•

beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first, second, and third quarters 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 ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019;

•	allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements), with $385.1 million of future incurrence available as of June 30, 2016;

•	limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and

•	limits the amount spent on repurchases or other redemptions of our senior subordinated notes to $225 million, with $169.5 million available as of June 30, 2016.

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(1)	Ranges presented for fixed-price 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.

(2)

A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

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•	Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

•

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2016, instruments in this category include non-exchange-traded 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 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 $80 thousand in the fair value of these instruments as of June 30, 2016.

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•	for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio);

•	for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0;

•

beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first, second, and third quarters 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 ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019;

•	allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements), with $385.1 million of future incurrence available as of June 30, 2016;

•	limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and

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•	limits the amount spent on repurchases or other redemptions of our senior subordinated notes to $225 million, with $169.5 million available as of June 30, 2016.

•	$100 million allocated for tertiary oil field expenditures;

•	$35 million allocated for other areas, primarily non-tertiary oil field expenditures;

•	$10 million to be spent on CO2 sources and pipeline construction; and

•	$55 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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(1)	Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

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(1)	Includes full cost pool ceiling test write-downs of $479.4 million and $735.4 million for the three and six months ended June 30, 2016, respectively, and $1.7 billion and $1.9 billion for the three and six months ended June 30, 2015, respectively.

(2)	Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).

(3)	See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.

(4)

Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $52.0 million and $124.3 million for the three and six months ended June 30, 2016, compared to receipts on settlements of $124.2 million and $272.6 million for the three and six months ended June 30, 2015. We believe that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the periods presented. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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(1)	Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields.

(2)	Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, expected to close in the third quarter of 2016.

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(1)	Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value adjustments on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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(1)	Cash interest is presented on an accrual basis, and includes interest on our new 2021 Senior Secured Notes (interest on which is to be paid semi-annually May 15 and November 15 of each year, beginning November 15, 2016), which are accounted for as debt and not reflected as interest for financial reporting purposes. See below for further discussion.

(2)	Includes commitment fees but excludes debt issue costs and amortization of discount or premium.

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(1)	Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value adjustments on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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(1)	Stock repurchases during the second quarter of 2016 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights.

(2)

In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program, and do not anticipate repurchasing shares of our common stock as long as current commodity pricing and market conditions persist.

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*	Included herewith.

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(g)

the date of Holder’s Retirement Vesting Date, provided that such date is at least one year from the Date of Grant. In the event that Holder’s Retirement Vesting Date occurs prior to the first anniversary of the Date of Grant, the vesting date pursuant to this Paragraph 2(g) shall be the first anniversary of the Date of Grant, unless the Award Restricted Stock has been forfeited pursuant to Section 3.

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(a)	May 23, 2017 (“Anniversary Date”);

(d)	the date of a Post-Separation Change of Control.

(e)	incurs a Separation before the Anniversary Date (such date being the “Separation Date”); and

(f)	such Separation does not constitute a Separation for Cause or is not the result of conduct which could have otherwise led to a Separation for Cause.

(g)	equals the total number of Award Restricted Stock granted under this Award;

(h)	equals the number of days the Holder provided services as a Director during the Restricted Period up to and including the Separation Date (numerator); and

(i)	equals the total number of days during the Restricted Period beginning on the date the Holder began providing services as a Director and ending on the Anniversary Date (denominator).

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1.	I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

1.	I have reviewed this report on Form 10-Q of Denbury Resources Inc. (the registrant);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.

v3.5.0.2

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 31, 2016
Document And Company Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
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	0000945764
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		398,326,717

v3.5.0.2

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents		$ 2,545	$ 2,812
Accrued production receivable		120,473	100,413
Trade and other receivables, net		70,700	87,093
Derivative assets		4,699	142,846
Other current assets		14,402	10,005
Total current assets		212,819	343,169
Oil and natural gas properties (using full cost accounting)
Proved properties		10,346,027	10,245,195
Unevaluated properties		909,310	894,948
CO2 properties		1,186,596	1,187,458
Pipelines and plants		2,294,295	2,293,219
Other property and equipment		399,880	408,194
Less accumulated depletion, depreciation, amortization and impairment		(10,521,061)	(9,653,205)
Net property and equipment		4,615,047	5,375,809
Derivative assets		31	0
Other assets		162,076	166,555
Total assets		4,989,973	5,885,533
Current liabilities
Accounts payable and accrued liabilities		162,334	253,197
Oil and gas production payable		83,713	87,337
Derivative liabilities		107,105	0
Current maturities of long-term debt	[1]	83,762	32,481
Total current liabilities		436,914	373,015
Long-term liabilities
Long-term debt, net of current portion		2,998,268	3,245,114
Asset retirement obligations		143,981	138,919
Derivative liabilities		67	0
Deferred tax liabilities, net		519,207	852,089
Other liabilities		26,232	27,484
Total long-term liabilities		3,687,755	4,263,606
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; 395,347,234 and 354,541,626 shares issued, respectively		395	355
Paid-in capital in excess of par		2,520,760	2,353,549
Accumulated deficit		(1,608,701)	(1,058,954)
Treasury stock, at cost, 3,745,901 and 3,124,311 shares, respectively		(47,150)	(46,038)
Total stockholders' equity		865,304	1,248,912
Total liabilities and stockholders' equity		$ 4,989,973	$ 5,885,533
[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of June 30, 2016 include $51.0 million of future interest payable related to this balance that is due within the next twelve months. See 2016 Senior Subordinated Notes Exchange below for further discussion.

v3.5.0.2

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
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	395,347,234	354,541,626
Treasury stock, shares	3,745,901	3,124,311

v3.5.0.2

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues and other income
Oil, natural gas, and related product sales	$ 246,668	$ 366,891	$ 434,471	$ 664,361
CO2 sales and transportation fees	6,622	7,152	12,894	14,124
Interest income and other income	1,858	2,651	2,627	5,858
Total revenues and other income	255,148	376,694	449,992	684,343
Expenses
Lease operating expenses	100,019	132,170	202,466	273,254
Marketing and plant operating expenses	12,999	14,215	26,193	25,900
CO2 discovery and operating expenses	1,071	945	1,678	1,892
Taxes other than income	19,504	33,555	39,596	60,234
General and administrative expenses	22,545	37,947	56,446	84,227
Interest, net of amounts capitalized of $6,289, $8,738, $12,069, and $17,147, respectively	36,058	39,863	78,229	79,962
Depletion, depreciation, and amortization	66,541	147,940	143,907	297,898
Commodity derivatives expense (income)	98,209	48,926	121,035	(34,150)
Gain on debt extinguishment	(12,278)	0	(107,269)	0
Write-down of oil and natural gas properties	479,400	1,705,800	735,400	1,852,000
Other expenses	34,688	0	36,232	0
Total expenses	858,756	2,161,361	1,333,913	2,641,217
Loss before income taxes	(603,608)	(1,784,667)	(883,921)	(1,956,874)
Income tax benefit	(222,940)	(636,168)	(318,060)	(700,629)
Net loss	$ (380,668)	$ (1,148,499)	$ (565,861)	$ (1,256,245)
Net loss per common share
Basic	$ (1.03)	$ (3.28)	$ (1.58)	$ (3.59)
Diluted	(1.03)	(3.28)	(1.58)	(3.59)
Dividends declared per common share	$ 0	$ 0.0625	$ 0	$ 0.1250
Weighted average common shares outstanding
Basic	370,566	350,039	358,901	349,653
Diluted	370,566	350,039	358,901	349,653

v3.5.0.2

Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Expenses
Capitalized interest	$ 6,289	$ 8,738	$ 12,069	$ 17,147

v3.5.0.2

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (380,668)	$ (1,148,499)	$ (565,861)	$ (1,256,245)
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $0, $10, $0, and $21, respectively	0	18	0	35
Total other comprehensive income	0	18	0	35
Comprehensive loss	$ (380,668)	$ (1,148,481)	$ (565,861)	$ (1,256,210)

v3.5.0.2

Condensed Consolidated Statements of Comprehensive Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Other comprehensive income, net of income tax:
Tax for interest rate lock derivative contracts reclassified to income	$ 0	$ 10	$ 0	$ 21

v3.5.0.2

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities
Net loss	$ (565,861)	$ (1,256,245)
Adjustments to reconcile net loss to cash flows from operating activities
Depletion, depreciation, and amortization	143,907	297,898
Write-down of oil and natural gas properties	735,400	1,852,000
Deferred income taxes	(318,055)	(700,508)
Stock-based compensation	4,122	14,967
Commodity derivatives expense (income)	121,035	(34,150)
Receipt on settlements of commodity derivatives	124,253	272,616
Gain on debt extinguishment	(107,269)	0
Debt issuance costs and discounts	14,072	4,501
Other, net	(1,743)	(4,019)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(20,060)	17,683
Trade and other receivables	17,568	57,865
Other current and long-term assets	(7,974)	(7,770)
Accounts payable and accrued liabilities	(71,830)	(71,892)
Oil and natural gas production payable	(3,624)	(13,217)
Other liabilities	(997)	(3,008)
Net cash provided by operating activities	62,944	426,721
Cash flows from investing activities
Oil and natural gas capital expenditures	(126,302)	(276,783)
CO2 capital expenditures	(451)	(15,608)
Pipelines and plants capital expenditures	(1,965)	(20,349)
Other	1,198	(23,772)
Net cash used in investing activities	(127,520)	(336,512)
Cash flows from financing activities
Bank repayments	(994,000)	(1,007,000)
Bank borrowings	1,139,000	962,000
Repurchases of senior subordinated notes	(55,521)	0
Pipeline financing and capital lease debt repayments	(14,336)	(17,122)
Cash dividends paid	(413)	(43,528)
Other	(10,421)	(3,299)
Net cash provided by (used in) financing activities	64,309	(108,949)
Net decrease in cash and cash equivalents	(267)	(18,740)
Cash and cash equivalents at beginning of period	2,812	23,153
Cash and cash equivalents at end of period	$ 2,545	$ 4,413

v3.5.0.2

Condensed Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) $ in Thousands	Total	Common Stock ($.001 Par Value)	Paid-In Capital in Excess of Par	Retained Earnings (Accumulated Deficit)	Treasury Stock (at cost)
Beginning balance, shares at Dec. 31, 2015	354,541,626	354,541,626			3,124,311
Beginning balance at Dec. 31, 2015	$ 1,248,912	$ 355	$ 2,353,549	$ (1,058,954)	$ (46,038)
Issued or purchased pursuant to employee stock compensation plans, shares		44,346
Issued pursuant to directors' compensation plan, shares		31,930
Issued pursuant to directors' compensation plan, value	50		50
Issued as part of debt exchange, shares		40,729,332
Issued as part of debt exchange, value	160,491	$ 40	160,451
Stock-based compensation	7,125		7,125
Tax withholding - stock compensation, shares					621,590
Tax withholding - stock compensation, value	(1,112)				$ (1,112)
Dividends adjustments	42			42
Net loss	$ (565,861)			(565,861)
Ending balance, shares at Jun. 30, 2016	395,347,234	395,347,234			3,745,901
Ending balance at Jun. 30, 2016	$ 865,304	$ 395	2,520,760	(1,608,701)	$ (47,150)
Cumulative effect of accounting change	$ 15,657		$ (415)	$ 16,072

v3.5.0.2

Basis of Presentation	6 Months Ended
	Jun. 30, 2016
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 CO2 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, 2015 (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, 2016, our consolidated results of operations for the three and six months ended June 30, 2016 and 2015, our consolidated cash flows for the six months ended June 30, 2016 and 2015, and our consolidated statement of changes in stockholders’ equity for the six months ended June 30, 2016. Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, (1) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (2) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows. Net Loss per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock, stock options, stock appreciation rights (“SARs”), and nonvested performance-based equity awards.  For the three and six months ended June 30, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Basic weighted average common shares outstanding   370,566   350,039   358,901   349,653 Potentially dilutive securities                 Restricted stock, stock options, SARs and performance-based equity awards   —   —   —   — Diluted weighted average common shares outstanding   370,566   350,039   358,901   349,653 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 loss per common share (although time-vesting restricted stock is issued and outstanding upon grant). The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Stock options and SARs   6,265   9,949   6,839   10,228 Restricted stock and performance-based equity awards   4,374   2,241   4,491   2,595 Write-Down of Oil and Natural Gas Properties The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves has fallen throughout 2015 and the first half of 2016, from $71.68 per Bbl for the second quarter of 2015 to $43.12 per Bbl for the second quarter of 2016. In addition, the average first-day-of-the-month NYMEX natural gas price used in estimating our proved reserves was $3.38 per MMBtu for the second quarter of 2015 and $2.33 per MMBtu for the second quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $479.4 million and $256.0 million during the three months ended June 30 and March 31, 2016, respectively, and $1.7 billion and $146.2 million during the three months ended June 30 and March 31, 2015, respectively. Recent Accounting Pronouncements Recently Adopted Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods. Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows. Debt Issuance Costs. In April 2015, the FASB issued 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. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs of $32.8 million associated with our previously issued senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows for any periods. Not Yet Adopted Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have 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. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. 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 these standards will have on our consolidated financial statements.

v3.5.0.2

Long-Term Debt	6 Months Ended
	Jun. 30, 2016
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   2016   2015 Senior Secured Bank Credit Agreement   $ 320,000 $ 175,000 9% Senior Secured Second Lien Notes due 2021   614,919 — 6⅜% Senior Subordinated Notes due 2021   220,939 400,000 5½% Senior Subordinated Notes due 2022   796,712 1,250,000 4⅝% Senior Subordinated Notes due 2023   622,297 1,200,000 Other Subordinated Notes, including premium of $5 and $7, respectively   2,255 2,257 Pipeline financings   207,448 211,766 Capital lease obligations   60,124 71,324 Total principal balance   2,844,694 3,310,347 Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)   254,660 — Issuance costs on senior subordinated notes   (17,324 ) (32,752 ) Total debt, net of debt issuance costs on senior subordinated notes   3,082,030 3,277,595 Less: current maturities of long-term debt (1)   (83,762 ) (32,481 ) Long-term debt and capital lease obligations   $ 2,998,268 $ 3,245,114 (1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of June 30, 2016 include $51.0 million of future interest payable related to this balance that is due within the next twelve months. See 2016 Senior Subordinated Notes Exchange below for further discussion. The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior secured second lien notes and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries. Senior Secured Bank Credit Facility In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. In connection with our May 2016 borrowing base redetermination, our borrowing base and lender commitments were reduced to $1.05 billion, with the next such redetermination scheduled for November 2016. In order to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with maintenance financial covenants in this low oil price environment, we entered into three amendments to the Bank Credit Agreement between May 2015 and April 2016 that modified the Bank Credit Agreement as follows: • for 2016 and 2017, the maximum permitted ratio of consolidated total net debt to consolidated EBITDAX covenant has been suspended and replaced by a maximum permitted ratio of consolidated senior secured debt to consolidated EBITDAX covenant of 3.0 to 1.0 (currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio); • for 2016 and 2017, a new covenant has been added to require a minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; • beginning in the first quarter of 2018, the ratio of consolidated total net debt to consolidated EBITDAX covenant will be reinstated, utilizing an annualized EBITDAX amount for the first, second, and third quarters 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 ending March 31, 2018, 5.5 to 1.0 for the second quarter ending June 30, 2018, and 5.0 to 1.0 for the third and fourth quarters ending September 30 and December 31, 2018, and returning to 4.25 to 1.0 for the first quarter ending March 31, 2019; • allows for the incurrence of up to $1.0 billion of junior lien debt (subject to customary requirements), with $385.1 million of future incurrence available as of June 30, 2016; • limits unrestricted cash and cash equivalents to $225 million if more than $250 million of borrowings are outstanding under the Bank Credit Agreement; and • limits the amount spent on repurchases or other redemptions of our senior subordinated notes to $225 million, with $169.5 million available as of June 30, 2016. Additionally, such amendments made the following changes to the Bank Credit Agreement: (1) increased the applicable margin for ABR Loans and LIBOR Loans by 75 basis points such that the margin for ABR Loans now ranges from 1% to 2% per annum and the margin for LIBOR Loans now ranges from 2% to 3% per annum, (2) increased the commitment fee rate to 0.50%, and (3) provided for semi-annual scheduled redeterminations of the borrowing base in May and November of each year. As of June 30, 2016, we were in compliance with all debt covenants under the Bank Credit Agreement. The weighted average interest rate on borrowings outstanding as of June 30, 2016, under the Bank Credit Agreement was 2.8%. The above description of our Bank Credit Agreement financial covenants and the changes provided for within the three amendments are qualified by the express language and defined terms contained in the Bank Credit Agreement, the First Amendment to the Bank Credit Agreement dated May 4, 2015, the Second Amendment to the Bank Credit Agreement dated February 17, 2016, and the Third Amendment to the Bank Credit Agreement dated April 18, 2016, each of which are filed as exhibits to our periodic reports filed with the SEC. 2016 Senior Subordinated Notes Exchange During May 2016, we entered into privately negotiated exchange agreements to exchange a total of $1,057.8 million of our existing senior subordinated notes for $614.9 million principal amount of our 9% Senior Secured Second Lien Notes due 2021(the “2021 Senior Secured Notes”) plus 40.7 million shares of Denbury common stock, resulting in a net reduction from these exchanges of $442.9 million in our debt principal. The exchanged notes consisted of $175.1 million principal amount of our 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”), $411.0 million principal amount of our 5½% Senior Subordinated Notes due 2022 (“2022 Notes”), and $471.7 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 (“2023 Notes”). In accordance with FASB ASC 470-60, the exchanges were accounted for as a troubled debt restructuring due to the level of concession provided by our lenders. Under this guidance, future interest applicable to the 2021 Senior Secured Notes is recorded as debt up to the point that the principal and future interest of the new notes is equal to the principal amount of the extinguished notes, rather than recognizing a gain on extinguishment for this amount. As a result, $254.7 million of future interest on the 2021 Senior Secured Notes has been recorded as debt, which will be reduced as semi-annual interest payments are made, with the remaining $22.8 million of future interest to be recognized as interest expense over the term of these notes. Therefore, future interest expense on the 2021 Senior Secured Notes will be significantly lower than the actual cash interest payments. In addition, we recognized a gain of $12.3 million as a result of this debt exchange, which is included in “Gain on debt extinguishment” in the accompanying Unaudited Condensed Consolidated Statements of Operations. 9% Senior Secured Second Lien Notes due 2021 In May 2016, we issued $614.9 million of 2021 Senior Secured Notes.  The 2021 Senior Secured Notes, which bear interest at a rate of 9% per annum, were issued at par in connection with privately negotiated exchanges with a limited number of holders of $1,057.8 million of existing senior subordinated notes (see 2016 Senior Subordinated Notes Exchange above).  The 2021 Senior Secured Notes mature on May 15, 2021, and interest is payable semi-annually in arrears on May 15 and November 15 of each year, beginning November 15, 2016.  We may redeem the 2021 Senior Secured Notes in whole or in part at our option beginning December 15, 2018, at a redemption price of 109% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2021 Senior Secured Notes (the “Indenture”).  Prior to December 15, 2018, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Senior Secured Notes at a price of 109% of par with the proceeds of certain equity offerings.  In addition, at any time prior to December 15, 2018, we may redeem the 2021 Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest.  The 2021 Senior Secured Notes are not subject to any sinking fund requirements. The Indenture contains customary covenants that restrict our ability and the ability of our restricted subsidiaries’ to (1) incur additional debt; (2) make investments; (3) create liens on our assets or the assets of our restricted subsidiaries; (4) create limitations on the ability of our restricted subsidiaries to pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt (including existing senior subordinated notes)), provided that in certain circumstances we may make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (as defined in the Indenture) not to exceed 2.5 to 1.0 (both before and after giving effect to any restricted payment). The 2021 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt. 2016 Repurchases of Senior Subordinated Notes During February and March 2016, we repurchased a total of $152.3 million of our outstanding long-term indebtedness, consisting of $4.0 million principal amount of our 2021 Notes, $42.3 million principal amount of our 2022 Notes, and $106.0 million principal amount of our 2023 Notes in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off. During July 2016, we repurchased an additional $19.6 million of senior subordinated notes in open-market transactions, consisting of $3.3 million principal amount of our 2021 Notes and $16.3 million principal amount of our 2022 Notes, for a total purchase price of $14.2 million, excluding accrued interest. As of August 3, 2016, under the Bank Credit Agreement, an additional $155.3 million may be spent on senior subordinated notes repurchases or other redemptions.

v3.5.0.2

Income Taxes	6 Months Ended
	Jun. 30, 2016
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, 2016, we had $34.5 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 tax valuation allowances totaling $33.6 million during 2015 and an additional $0.9 million during the first quarter of 2016, which reduced 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. As of June 30, 2016, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during the fourth quarter of 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of June 30, 2016. In connection with the privately negotiated exchange agreements to exchange a portion of our existing senior subordinated notes for 2021 Senior Secured Notes, we realized a tax gain due to the concession extended by our note holders. This tax gain was offset by net operating losses and other deferred tax asset attributes.

v3.5.0.2

Stockholders' Equity	6 Months Ended
	Jun. 30, 2016
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Note 4. Stockholders’ Equity Dividends During the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share, with dividends totaling $43.5 million paid to stockholders during the six months ended June 30, 2015. In September 2015, in light of the continuing low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.

v3.5.0.2

Commodity Derivative Contracts	6 Months Ended
	Jun. 30, 2016
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. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps 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. 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, 2016, 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, 2016, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months   Index Price   Volume (Barrels per day)   Contract Prices ($/Bbl) Range (1)   Weighted Average Price Swap   Sold Put   Floor   Ceiling Oil Contracts:                               2016 Fixed-Price Swaps                               July – Sept   NYMEX   18,500   $ 36.25 – 45.08   $ 38.96   $ —   $ —   $ — July – Sept   LLS   7,000     37.24 – 42.15   39.61   —   —   — Oct – Dec   NYMEX   26,000     36.25 – 45.40   38.70   —   —   — Oct – Dec   LLS   7,000     37.24 – 41.00   39.16   —   —   — 2016 Collars                                   July – Sept   NYMEX   4,500   $ 55.00 – 72.65   $ —   $ —   $ 55.00   $ 71.22 July – Sept   NYMEX   4,000     40.00 – 51.80   —   —   40.00   51.40 July – Sept   LLS   3,000     58.00 – 74.30   —   —   58.00   73.85 July – Sept   LLS   5,000     40.00 – 54.25   —   —   40.00   53.74 Oct – Dec   NYMEX   4,000     40.00 – 54.00   —   —   40.00   53.48 Oct – Dec   LLS   4,000     40.00 – 56.00   —   —   40.00   55.79 2017 Fixed-Price Swaps                               Jan – Mar   NYMEX   22,000   $ 41.15 – 45.45   $ 42.67   $ —   $ —   $ — Jan – Mar   LLS   10,000     42.35 – 46.15   43.77   —   —   — Apr – June   NYMEX   22,000     41.20 – 46.50   43.99   —   —   — Apr – June   LLS   7,000     42.65 – 46.65   45.35   —   —   — 2017 Collars                                   Jan – Mar   NYMEX   4,000   $ 40.00 – 55.40   $ —   $ —   $ 40.00   $ 54.80 Jan – Mar   LLS   3,000     40.00 – 57.35   —   —   40.00   57.23 2017 Three-Way Collars (2)                               July – Sept   NYMEX   6,500   $ 40.00 – 70.25   $ —   $ 30.00   $ 40.00   $ 69.74 July – Sept   LLS   1,000     41.00 – 69.25   —   31.00   41.00   69.25 (1) Ranges presented for fixed-price 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. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

v3.5.0.2

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
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 derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2016, instruments in this category include non-exchange-traded 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 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 $80 thousand in the fair value of these instruments as of June 30, 2016. 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, 2016                 Assets                 Oil derivative contracts – current   $ —   $ 2,619   $ 2,080   $ 4,699 Oil derivative contracts – long-term   —   31   —   31 Total Assets   $ —   $ 2,650   $ 2,080   $ 4,730                   Liabilities                 Oil derivative contracts – current   $ —   $ 105,310   $ 1,795   $ 107,105 Oil derivative contracts – long-term   —   22   45   67 Total Liabilities   $ —   $ 105,332   $ 1,840   $ 107,172                   December 31, 2015                 Assets                 Oil derivative contracts – current   $ —   $ 90,012   $ 52,834   $ 142,846 Total Assets   $ —   $ 90,012   $ 52,834   $ 142,846 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, 2016 and 2015:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Fair value of Level 3 instruments, beginning of period   $ 23,040   $ 165,015   $ 52,834   $ 188,446 Fair value adjustments on commodity derivatives   (4,818 )   (7,302 )   (4,536 )   17,783 Receipts on settlements of commodity derivatives   (17,982 )   (45,355 )   (48,058 )   (93,871 ) Fair value of Level 3 instruments, end of period   $ 240   $ 112,358   $ 240   $ 112,358                   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   $ (3,857 )   $ (4,325 )   $ (3,870 )   $ 14,142 We utilize an income approach to value our Level 3 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 6/30/2016 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 240   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2016   21.1% - 41.4% Other Fair Value Measurements The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes and senior subordinated notes are based on quoted market prices. The estimated fair value of the principal amount of our debt as of June 30, 2016 and December 31, 2015, excluding pipeline financing and capital lease obligations, was $2,033.6 million and $1,119.0 million, respectively, which increase is primarily driven by an increase in quoted market prices. 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.

v3.5.0.2

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 7. Commitments and Contingencies Commitments In the second quarter of 2016, we amended our CO2 offtake agreement with Mississippi Power Company (“MSPC”), which amendment included increasing our offtake percentage from 70% to 100% of CO2 quantities produced and lowering the base price related to the cost of CO2, deliveries of which are currently expected to begin in the second half of 2016. Based on the amended terms in the agreement, we concluded for accounting purposes that the agreement contains an embedded lease related to the pipeline owned by MSPC used to transport CO2 to Denbury. We currently plan to record a capital lease on the balance sheet of approximately $110 million upon lease commencement. Litigation 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. NGS Sub Corp., Evolution, et al v. Denbury Onshore, LLC On June 24, 2016, we entered into a settlement agreement with Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”) resolving all outstanding disputes and claims the parties had or may have had against each other, including pending litigation claims, involving the Delhi Field in northeastern Louisiana. In addition to clarifying certain aspects of the parties’ ongoing relationship as joint interest holders in the Delhi Field, the settlement resolves (1) claims by Denbury related to the purchase of our original Delhi Field interest from Evolution; (2) disputes regarding the occurrence, determination, timing, nature and terms of “payout” and Evolution’s related reversionary interest in the Delhi Field; and (3) any claims by Evolution in connection with the June 2013 incident at the Delhi Field (the “June 2013 Incident”). Under the terms of the settlement agreement, (1) we paid Evolution $27.5 million in cash on June 30, 2016; (2) effective July 1, 2016, Denbury conveyed to Evolution 25% of the interests in the Mengel Sand Interval, a separate interval within the Delhi Unit which we purchased for approximately $6.5 million in late 2014, and which interval is not currently producing; (3) effective July 1, 2016, we were credited with an additional 0.2226% overriding royalty interest in the Holt-Bryant interval (the currently producing interval of the Delhi Unit); (4) the parties reached agreement as to the ownership of certain field assets, and established future CO2 pipeline transportation charges following the end of the current ten-year fixed price arrangement set to expire in 2019; (5) Evolution waived and released any claims it may have to any insurance proceeds that may be received as a result of existing claims made by Denbury with respect to the June 2013 Incident; and (6) on July 11, 2016, the Court dismissed with prejudice the pending Delhi Field litigation between the parties. The cash payment was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations in the second quarter of 2016.

v3.5.0.2

Additional Balance Sheet Details	6 Months Ended
	Jun. 30, 2016
Disclosure Text Block [Abstract]
Additional Balance Sheet Details	Note 8. Additional Balance Sheet Details Accounts Payable and Accrued Liabilities     June 30,   December 31, In thousands   2016   2015 Accrued interest   $ 29,182   $ 48,908 Accrued lease operating expenses   28,482   37,549 Accounts payable   24,675   30,477 Taxes payable   19,342   32,438 Accrued compensation   16,423   46,780 Accrued exploration and development costs   4,906   20,892 Other   39,324   36,153 Total   $ 162,334   $ 253,197

v3.5.0.2

Subsequent Event	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Event	Note 9. Subsequent Event Employee Equity Award Grant The Compensation Committee of our Board of Directors granted customary long-term equity incentive awards to our employees under the 2004 Omnibus Stock and Incentive Plan on July 8, 2016 covering 6,851,346 shares of restricted stock. The closing price of Denbury’s common stock on July 8, 2016 was $3.22 per share. The awards generally vest one-third per year over a three-year period.

v3.5.0.2

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
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, 2015 (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, 2016, our consolidated results of operations for the three and six months ended June 30, 2016 and 2015, our consolidated cash flows for the six months ended June 30, 2016 and 2015, and our consolidated statement of changes in stockholders’ equity for the six months ended June 30, 2016.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Balance Sheets, (1) debt issuance costs associated with our senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” and (2) deferred tax assets have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net.” Such reclassifications were made as a result of our adoption of new accounting pronouncements described in Recent Accounting Pronouncements – Recently Adopted below and had no impact on our previously reported net income or cash flows.
Net Loss per Common Share	Net Loss per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net loss per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock, stock options, stock appreciation rights (“SARs”), and nonvested performance-based equity awards.  For the three and six months ended June 30, 2016 and 2015, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net loss per common share calculations for the periods indicated:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Basic weighted average common shares outstanding   370,566   350,039   358,901   349,653 Potentially dilutive securities                 Restricted stock, stock options, SARs and performance-based equity awards   —   —   —   — Diluted weighted average common shares outstanding   370,566   350,039   358,901   349,653 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 loss per common share (although time-vesting restricted stock is issued and outstanding upon grant). The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Stock options and SARs   6,265   9,949   6,839   10,228 Restricted stock and performance-based equity awards   4,374   2,241   4,491   2,595
Oil and Natural Gas Properties Policy	Write-Down of Oil and Natural Gas Properties The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. As a result of the precipitous and continuing decline in NYMEX oil prices since the fourth quarter of 2014, the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves has fallen throughout 2015 and the first half of 2016, from $71.68 per Bbl for the second quarter of 2015 to $43.12 per Bbl for the second quarter of 2016. In addition, the average first-day-of-the-month NYMEX natural gas price used in estimating our proved reserves was $3.38 per MMBtu for the second quarter of 2015 and $2.33 per MMBtu for the second quarter of 2016. These falling prices have led to our recognizing full cost pool ceiling test write-downs of $479.4 million and $256.0 million during the three months ended June 30 and March 31, 2016, respectively, and $1.7 billion and $146.2 million during the three months ended June 30 and March 31, 2015, respectively.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective January 1, 2016, we adopted ASU 2016-09. The amendments within ASU 2016-09 related to the timing of when excess tax benefits are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, relating to the timing of recognition of excess tax benefits, representing a $15.7 million reduction to beginning “Accumulated deficit” with the offset to “Deferred tax liabilities, net” ($14.8 million) and “Other current assets” ($0.8 million). We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet on January 1, 2016, to reflect actual forfeitures versus the previously-estimated forfeiture rate, representing a $0.4 million reduction to “Accumulated deficit” with the offset to “Paid-in capital in excess of par.” The amendments within ASU 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statement of cash flows were adopted prospectively, with no adjustments made to prior periods. Income Taxes. In November 2015, the FASB issued ASU 2015-17, Income Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred income taxes and requires deferred tax assets and liabilities to be classified as noncurrent in the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and early adoption is permitted. Entities can transition to the standard either retrospectively to each period presented or prospectively. Effective January 1, 2016, we adopted ASU 2015-17, which has been applied retrospectively for all comparative periods presented. Accordingly, current deferred tax assets of $1.5 million have been reclassified from “Deferred tax assets, net” to “Deferred tax liabilities, net” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-17 did not have an impact on our consolidated results of operations or cash flows. Debt Issuance Costs. In April 2015, the FASB issued 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. Entities are required to apply the guidance on a retrospective basis to each period presented as a change in accounting principle. In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-15”) which amends ASU 2015-03 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, such that entities may continue to apply current practice. Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which have been applied retrospectively for all comparative periods presented. Accordingly, debt issuance costs of $32.8 million associated with our previously issued senior subordinated notes have been reclassified from “Other assets” to “Long-term debt, net of current portion” in our Unaudited Condensed Consolidated Balance Sheet as of December 31, 2015. The adoption of ASU 2015-03 and ASU 2015-15 did not have an impact on our consolidated results of operations or cash flows for any periods. Not Yet Adopted Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. Management is currently assessing the impact the adoption of ASU 2016-02 will have 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. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (“ASU 2015-14”) which amends ASU 2014-09 and delays the effective date for public companies, such that the amendments in the ASU are effective for reporting periods beginning after December 15, 2017, and early adoption will be permitted for periods beginning after December 15, 2016. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. 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 these standards 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. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps 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. 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, 2016, 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 derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2016, instruments in this category include non-exchange-traded 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 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 $80 thousand in the fair value of these instruments as of June 30, 2016. We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

v3.5.0.2

Basis of Presentation (Tables)	6 Months Ended
	Jun. 30, 2016
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 loss per common share calculations for the periods indicated:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Basic weighted average common shares outstanding   370,566   350,039   358,901   349,653 Potentially dilutive securities                 Restricted stock, stock options, SARs and performance-based equity awards   —   —   —   — Diluted weighted average common shares outstanding   370,566   350,039   358,901   349,653
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 loss per share, as their effect would have been antidilutive:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Stock options and SARs   6,265   9,949   6,839   10,228 Restricted stock and performance-based equity awards   4,374   2,241   4,491   2,595

v3.5.0.2

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
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   2016   2015 Senior Secured Bank Credit Agreement   $ 320,000 $ 175,000 9% Senior Secured Second Lien Notes due 2021   614,919 — 6⅜% Senior Subordinated Notes due 2021   220,939 400,000 5½% Senior Subordinated Notes due 2022   796,712 1,250,000 4⅝% Senior Subordinated Notes due 2023   622,297 1,200,000 Other Subordinated Notes, including premium of $5 and $7, respectively   2,255 2,257 Pipeline financings   207,448 211,766 Capital lease obligations   60,124 71,324 Total principal balance   2,844,694 3,310,347 Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)   254,660 — Issuance costs on senior subordinated notes   (17,324 ) (32,752 ) Total debt, net of debt issuance costs on senior subordinated notes   3,082,030 3,277,595 Less: current maturities of long-term debt (1)   (83,762 ) (32,481 ) Long-term debt and capital lease obligations   $ 2,998,268 $ 3,245,114

v3.5.0.2

Commodity Derivative Contracts (Tables)	6 Months Ended
	Jun. 30, 2016
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, 2016, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: Months   Index Price   Volume (Barrels per day)   Contract Prices ($/Bbl) Range (1)   Weighted Average Price Swap   Sold Put   Floor   Ceiling Oil Contracts:                               2016 Fixed-Price Swaps                               July – Sept   NYMEX   18,500   $ 36.25 – 45.08   $ 38.96   $ —   $ —   $ — July – Sept   LLS   7,000     37.24 – 42.15   39.61   —   —   — Oct – Dec   NYMEX   26,000     36.25 – 45.40   38.70   —   —   — Oct – Dec   LLS   7,000     37.24 – 41.00   39.16   —   —   — 2016 Collars                                   July – Sept   NYMEX   4,500   $ 55.00 – 72.65   $ —   $ —   $ 55.00   $ 71.22 July – Sept   NYMEX   4,000     40.00 – 51.80   —   —   40.00   51.40 July – Sept   LLS   3,000     58.00 – 74.30   —   —   58.00   73.85 July – Sept   LLS   5,000     40.00 – 54.25   —   —   40.00   53.74 Oct – Dec   NYMEX   4,000     40.00 – 54.00   —   —   40.00   53.48 Oct – Dec   LLS   4,000     40.00 – 56.00   —   —   40.00   55.79 2017 Fixed-Price Swaps                               Jan – Mar   NYMEX   22,000   $ 41.15 – 45.45   $ 42.67   $ —   $ —   $ — Jan – Mar   LLS   10,000     42.35 – 46.15   43.77   —   —   — Apr – June   NYMEX   22,000     41.20 – 46.50   43.99   —   —   — Apr – June   LLS   7,000     42.65 – 46.65   45.35   —   —   — 2017 Collars                                   Jan – Mar   NYMEX   4,000   $ 40.00 – 55.40   $ —   $ —   $ 40.00   $ 54.80 Jan – Mar   LLS   3,000     40.00 – 57.35   —   —   40.00   57.23 2017 Three-Way Collars (2)                               July – Sept   NYMEX   6,500   $ 40.00 – 70.25   $ —   $ 30.00   $ 40.00   $ 69.74 July – Sept   LLS   1,000     41.00 – 69.25   —   31.00   41.00   69.25 (1) Ranges presented for fixed-price 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. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

v3.5.0.2

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
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, 2016                 Assets                 Oil derivative contracts – current   $ —   $ 2,619   $ 2,080   $ 4,699 Oil derivative contracts – long-term   —   31   —   31 Total Assets   $ —   $ 2,650   $ 2,080   $ 4,730                   Liabilities                 Oil derivative contracts – current   $ —   $ 105,310   $ 1,795   $ 107,105 Oil derivative contracts – long-term   —   22   45   67 Total Liabilities   $ —   $ 105,332   $ 1,840   $ 107,172                   December 31, 2015                 Assets                 Oil derivative contracts – current   $ —   $ 90,012   $ 52,834   $ 142,846 Total Assets   $ —   $ 90,012   $ 52,834   $ 142,846
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, 2016 and 2015:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2016   2015   2016   2015 Fair value of Level 3 instruments, beginning of period   $ 23,040   $ 165,015   $ 52,834   $ 188,446 Fair value adjustments on commodity derivatives   (4,818 )   (7,302 )   (4,536 )   17,783 Receipts on settlements of commodity derivatives   (17,982 )   (45,355 )   (48,058 )   (93,871 ) Fair value of Level 3 instruments, end of period   $ 240   $ 112,358   $ 240   $ 112,358                   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   $ (3,857 )   $ (4,325 )   $ (3,870 )   $ 14,142
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 6/30/2016 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 240   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2016   21.1% - 41.4%

v3.5.0.2

Additional Balance Sheet Details (Tables)	6 Months Ended
	Jun. 30, 2016
Table Text Block [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities     June 30,   December 31, In thousands   2016   2015 Accrued interest   $ 29,182   $ 48,908 Accrued lease operating expenses   28,482   37,549 Accounts payable   24,675   30,477 Taxes payable   19,342   32,438 Accrued compensation   16,423   46,780 Accrued exploration and development costs   4,906   20,892 Other   39,324   36,153 Total   $ 162,334   $ 253,197

v3.5.0.2

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Weighted average shares used in the basic and diluted net income per common share
Basic weighted average common shares outstanding	370,566	350,039	358,901	349,653
Potentially dilutive securities
Restricted stock, stock options, SARs and performance-based equity awards	0	0	0	0
Diluted weighted average common shares outstanding	370,566	350,039	358,901	349,653

v3.5.0.2

Basis of Presentation (Antidilutive Securities) (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
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	6,265	9,949	6,839	10,228
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	4,374	2,241	4,491	2,595

v3.5.0.2

Basis of Presentation (Details Textuals) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016 USD ($) $ / MMBTU $ / Barrel	Mar. 31, 2016 USD ($)	Jun. 30, 2015 USD ($) $ / MMBTU $ / Barrel	Mar. 31, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Accounting Policies [Abstract]
Write-down of oil and natural gas properties | $	$ 479,400	$ 256,000	$ 1,705,800	$ 146,200	$ 735,400	$ 1,852,000
Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Oil and Natural Gas Prices | $ / Barrel	43.12		71.68
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Oil and Natural Gas Prices | $ / MMBTU	2.33		3.38

v3.5.0.2

Basis of Presentation Basis of Presentation (Details Textuals 2) - USD ($) $ in Thousands	Jun. 30, 2016	Jan. 01, 2016	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
Current deferred tax assets, Net			$ 1,500
Issuance costs on senior subordinated notes	$ 17,324		32,752
New Accounting Pronouncement, Early Adoption [Line Items]
Retained Earnings (Accumulated Deficit)	(1,608,701)		(1,058,954)
Additional Paid-in Capital	(2,520,760)		(2,353,549)
Other Assets, Current	$ 14,402		$ 10,005
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Retained Earnings (Accumulated Deficit)		$ 15,700
Deferred Tax Liabilities, Net		14,800
Other Assets, Current		800
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Retained Earnings (Accumulated Deficit)		400
Additional Paid-in Capital		$ 400

v3.5.0.2

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands		Jun. 30, 2016	May 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior Secured Bank Credit Agreement		$ 320,000		$ 175,000
9% Senior Secured Second Lien Notes due 2021		614,919	$ 614,900	0
Pipeline financings		207,448		211,766
Capital Lease Obligations		60,124		71,324
Total principal balance		2,844,694		3,310,347
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021		254,660		0
Issuance costs on senior subordinated notes		(17,324)		(32,752)
Total debt, net of debt issuance costs on senior subordinated notes		3,082,030		3,277,595
Less: current maturities of long-term debt	[1]	(83,762)		(32,481)
Long-term debt and capital lease obligations		2,998,268		3,245,114
9% Senior Secured Second Lien Notes Due 2021
Debt Instrument [Line Items]
9% Senior Secured Second Lien Notes due 2021			$ 614,900
Less: current maturities of long-term debt		$ (51,000)
Debt Instrument, Interest Rate, Stated Percentage		9.00%
6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 220,939		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		$ 796,712		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		$ 622,297		1,200,000
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Other Subordinated Notes
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 2,255		2,257
Including premium of		$ 5		$ 7
[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 represents most of the interest due over the term of this obligation, which has been accounted for as debt in accordance with Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of June 30, 2016 include $51.0 million of future interest payable related to this balance that is due within the next twelve months. See 2016 Senior Subordinated Notes Exchange below for further discussion.

v3.5.0.2

Long-Term Debt (Details Textuals)	1 Months Ended	3 Months Ended			6 Months Ended
	May 31, 2016 USD ($) shares	Jun. 30, 2016 USD ($) shares	Mar. 31, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) shares	Jun. 30, 2015 USD ($)	Aug. 03, 2016 USD ($)	Jul. 30, 2016 USD ($)	Dec. 31, 2015 USD ($) shares
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%			100.00%
Senior Secured Bank Credit Facility [Abstract]
Line of Credit, Borrowing Base		$ 1,050,000,000.00			$ 1,050,000,000.00
Line of Credit Facility, Current Borrowing Capacity		1,050,000,000			$ 1,050,000,000
Weighted average interest rate on Bank Credit Facility					2.80%
Maximum amount of junior lien debt permitted		1,000,000,000.0			$ 1,000,000,000.0
Remaining junior lien debt allowed to be incurred					385,100,000
Senior subordinated notes available for repurchase		$ 169,500,000			$ 169,500,000
Subordinated Debt [Abstract]
Debt Instrument, Amount Exchanged	$ 1,057,800,000
Common stock issued as part of debt exchange | shares	40,700,000	395,347,234			395,347,234				354,541,626
Extinguishment of Debt, Amount	$ 442,900,000
Gain on debt extinguishment		$ 12,278,000		$ 0	$ 107,269,000	$ 0
Debt Instrument, Repurchased Face Amount			$ 152,300,000
Debt Instrument, Repurchase Amount			55,500,000
Secured Debt [Abstract]
9% Senior Secured Second Lien Notes due 2021	614,900,000	614,919,000			614,919,000				$ 0
Future interest payable on 9% Senior Secured Second Lien Notes Due 2021		254,660,000			254,660,000				$ 0
Interest Payable		$ 22,800,000			$ 22,800,000
Total Debt to EBITDA requirement					2.5
Debt Instrument, Redemption, Period One
Secured Debt [Abstract]
Debt Instrument, Redemption Price, Percentage					109.00%
Initial Redemption Period With Proceeds From Equity Offering
Secured Debt [Abstract]
Debt Instrument, Redemption Price, Percentage					109.00%
Debt Instrument, Percentage of Principal Amount Available To Be Redeemed					35.00%
Initial Redemption Period With Make Whole Premium
Secured Debt [Abstract]
Debt Instrument, Redemption Price, Percentage					100.00%
Year 2016
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to EBITDAX		3.0
EBITDAX to Consolidated Interest		1.25
Year 2017
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to EBITDAX		3.0
EBITDAX to Consolidated Interest		1.25
Q1 | Year 2018
Senior Secured Bank Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement					6.0
Q1 | Year 2019
Senior Secured Bank Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement					4.25
Q2 | Year 2018
Senior Secured Bank Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement					5.5
Q3 | Year 2018
Senior Secured Bank Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement					5.0
Q4 | Year 2018
Senior Secured Bank Credit Facility [Abstract]
Total Net Debt to EBITDAX Requirement					5.0
Line of Credit
Senior Secured Bank Credit Facility [Abstract]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
5 1/2% Senior Subordinated Notes due 2022
Subordinated Debt [Abstract]
Debt Instrument, Amount Exchanged					$ 411,000,000
Debt Instrument, Repurchased Face Amount			42,300,000
6 3/8% Senior Subordinated Notes due 2021
Subordinated Debt [Abstract]
Debt Instrument, Amount Exchanged					175,100,000
Debt Instrument, Repurchased Face Amount			4,000,000
4 5/8% Senior Subordinated Notes due 2023
Subordinated Debt [Abstract]
Debt Instrument, Amount Exchanged					$ 471,700,000
Debt Instrument, Repurchased Face Amount			106,000,000
9% Senior Secured Second Lien Notes Due 2021
Secured Debt [Abstract]
9% Senior Secured Second Lien Notes due 2021	$ 614,900,000
Cash and Cash Equivalents [Member] | Line of Credit
Senior Secured Bank Credit Facility [Abstract]
Credit Facility Covenants		$ 225,000,000
Maximum Outstanding Credit Facility Balance [Member] | Line of Credit
Senior Secured Bank Credit Facility [Abstract]
Credit Facility Covenants		250,000,000
Senior Subordinated Notes [Member]
Subordinated Debt [Abstract]
Gain on debt extinguishment			$ 95,000,000
Senior Subordinated Notes [Member] | Line of Credit
Senior Secured Bank Credit Facility [Abstract]
Credit Facility Covenants		$ 225,000,000
Base Rate [Member] | Line of Credit | Minimum
Senior Secured Bank Credit Facility [Abstract]
Interest Rate Margins on Bank Credit Facility		1.00%
Base Rate [Member] | Line of Credit | Maximum
Senior Secured Bank Credit Facility [Abstract]
Interest Rate Margins on Bank Credit Facility		2.00%
London Interbank Offered Rate (LIBOR) [Member] | Line of Credit | Minimum
Senior Secured Bank Credit Facility [Abstract]
Interest Rate Margins on Bank Credit Facility		2.00%
London Interbank Offered Rate (LIBOR) [Member] | Line of Credit | Maximum
Senior Secured Bank Credit Facility [Abstract]
Interest Rate Margins on Bank Credit Facility		3.00%
Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior subordinated notes available for repurchase							$ 155,300,000
Subordinated Debt [Abstract]
Debt Instrument, Repurchased Face Amount								$ 19,600,000
Debt Instrument, Repurchase Amount								14,200,000
Subsequent Event [Member] | 5 1/2% Senior Subordinated Notes due 2022
Subordinated Debt [Abstract]
Debt Instrument, Repurchased Face Amount								16,300,000
Subsequent Event [Member] | 6 3/8% Senior Subordinated Notes due 2021
Subordinated Debt [Abstract]
Debt Instrument, Repurchased Face Amount								$ 3,300,000

v3.5.0.2

Income Taxes (Details) - USD ($) $ in Millions	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	$ 34.5
Deferred Tax Assets, Valuation Allowance		$ 0.9	$ 33.6
Unrecognized Tax Benefits	$ 5.4

v3.5.0.2

Stockholders' Equity (Details Textuals) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Stockholders' Equity Note [Abstract]
Dividends declared per common share	$ 0	$ 0.0625	$ 0.0625	$ 0.0625	$ 0	$ 0.1250
Cash dividend payment					$ 413	$ 43,528

v3.5.0.2

Commodity Derivative Contracts (Details)	Jun. 30, 2016 bbl / d $ / Barrel
Swap | Year 2016 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	18,500
Weighted average swap price	38.96
Swap | Year 2016 | Q3 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	36.25
Swap | Year 2016 | Q3 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	45.08
Swap | Year 2016 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	7,000
Weighted average swap price	39.61
Swap | Year 2016 | Q3 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	37.24
Swap | Year 2016 | Q3 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	42.15
Swap | Year 2016 | Q4 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	26,000
Weighted average swap price	38.70
Swap | Year 2016 | Q4 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	36.25
Swap | Year 2016 | Q4 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	45.40
Swap | Year 2016 | Q4 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	7,000
Weighted average swap price	39.16
Swap | Year 2016 | Q4 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	37.24
Swap | Year 2016 | Q4 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	41.00
Swap | Year 2017 | Q1 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	22,000
Weighted average swap price	42.67
Swap | Year 2017 | Q1 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	41.15
Swap | Year 2017 | Q1 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	45.45
Swap | Year 2017 | Q1 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	10,000
Weighted average swap price	43.77
Swap | Year 2017 | Q1 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	42.35
Swap | Year 2017 | Q1 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	46.15
Swap | Year 2017 | Q2 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	22,000
Weighted average swap price	43.99
Swap | Year 2017 | Q2 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	41.20
Swap | Year 2017 | Q2 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	46.50
Swap | Year 2017 | Q2 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	7,000
Weighted average swap price	45.35
Swap | Year 2017 | Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	42.65
Swap | Year 2017 | Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	46.65
Collar | Year 2016 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	4,500
Derivative, Floor Price	55.00
Derivative, Cap Price	72.65
Weighted average floor price	55.00
Weighted average ceiling price	71.22
Collar | Year 2016 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	3,000
Derivative, Floor Price	58.00
Derivative, Cap Price	74.30
Weighted average floor price	58.00
Weighted average ceiling price	73.85
Collar | Year 2016 | Q4 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	4,000
Derivative, Floor Price	40.00
Derivative, Cap Price	54.00
Weighted average floor price	40.00
Weighted average ceiling price	53.48
Collar | Year 2016 | Q4 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	4,000
Derivative, Floor Price	40.00
Derivative, Cap Price	56.00
Weighted average floor price	40.00
Weighted average ceiling price	55.79
Collar | Year 2016 | Q3 (2) | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	4,000
Derivative, Floor Price	40.00
Derivative, Cap Price	51.80
Weighted average floor price	40.00
Weighted average ceiling price	51.40
Collar | Year 2016 | Q3 (2) | LLS
Derivative [Line Items]
Volume per Day | bbl / d	5,000
Derivative, Floor Price	40.00
Derivative, Cap Price	54.25
Weighted average floor price	40.00
Weighted average ceiling price	53.74
Collar | Year 2017 | Q1 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	4,000
Derivative, Floor Price	40.00
Derivative, Cap Price	55.40
Weighted average floor price	40.00
Weighted average ceiling price	54.80
Collar | Year 2017 | Q1 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	3,000
Derivative, Floor Price	40.00
Derivative, Cap Price	57.35
Weighted average floor price	40.00
Weighted average ceiling price	57.23
Three-way Collar | Year 2017 | Q3 | NYMEX
Derivative [Line Items]
Volume per Day | bbl / d	6,500
Derivative, Floor Price	40.00
Derivative, Cap Price	70.25
Weighted average sold put price	30.00
Weighted average floor price	40.00
Weighted average ceiling price	69.74
Three-way Collar | Year 2017 | Q3 | LLS
Derivative [Line Items]
Volume per Day | bbl / d	1,000
Derivative, Floor Price	41.00
Derivative, Cap Price	69.25
Weighted average sold put price	31.00
Weighted average floor price	41.00
Weighted average ceiling price	69.25

v3.5.0.2

Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	$ 4,699	$ 142,846
Oil derivative contracts - long-term asset	31	0
Total Assets	4,730	142,846
Oil derivative contracts - current liability	107,105	0
Oil derivative contracts - long-term liability	67	0
Total Liabilities	107,172
Quoted Prices in Active Markets (Level 1)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	0	0
Oil derivative contracts - long-term asset	0
Total Assets	0	0
Oil derivative contracts - current liability	0
Oil derivative contracts - long-term liability	0
Total Liabilities	0
Significant Other Observable Inputs (Level 2)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	2,619	90,012
Oil derivative contracts - long-term asset	31
Total Assets	2,650	90,012
Oil derivative contracts - current liability	105,310
Oil derivative contracts - long-term liability	22
Total Liabilities	105,332
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	2,080	52,834
Oil derivative contracts - long-term asset	0
Total Assets	2,080	$ 52,834
Oil derivative contracts - current liability	1,795
Oil derivative contracts - long-term liability	45
Total Liabilities	$ 1,840

v3.5.0.2

Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of period	$ 23,040	$ 165,015	$ 52,834	$ 188,446
Fair value adjustments on commodity derivatives	(4,818)	(7,302)	(4,536)	17,783
Receipts on settlements of commodity derivatives	(17,982)	(45,355)	(48,058)	(93,871)
Fair value of Level 3 instruments, end of period	240	112,358	240	112,358
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$ (3,857)	$ (4,325)	$ (3,870)	$ 14,142

v3.5.0.2

Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 240	$ 23,040	$ 52,834	$ 112,358	$ 165,015	$ 188,446
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	$ 240
Income Approach Valuation Technique | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	21.10%
Income Approach Valuation Technique | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	41.40%

v3.5.0.2

Fair Value Measurements (Details Textuals) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs	$ 80
Debt, Fair Value	$ 2,033,600	$ 1,119,000

v3.5.0.2

Commitments and Contingencies (Details) - USD ($) $ in Thousands		3 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2014	Jul. 01, 2016	Dec. 31, 2015
Other Commitments [Line Items]
Capital Lease Obligations	$ 60,124	$ 60,124				$ 71,324
CO2 Offtake Percentage		100.00%	70.00%
Litigation settlement, amount	27,500
Working Interest Conveyed In Litigation Settlement					25.00%
Payments to Acquire Oil and Gas Property				$ 6,500
Additional Overriding Royalty Interest Acquired in Oil and Gas Properties					0.2226%
Scenario, Forecast [Member]
Other Commitments [Line Items]
Capital Lease Obligations	$ 110,000	$ 110,000

v3.5.0.2

Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounts Payable and Accrued Liabilities, Current [Abstract]
Accrued interest	$ 29,182	$ 48,908
Accrued lease operating expenses	28,482	37,549
Accounts payable	24,675	30,477
Taxes payable	19,342	32,438
Accrued compensation	16,423	46,780
Accrued exploration and development costs	4,906	20,892
Other	39,324	36,153
Total	$ 162,334	$ 253,197

v3.5.0.2

Subsequent Event (Details Textuals) - Subsequent Event [Member]	Jul. 08, 2016 $ / shares shares
Subsequent Event [Line Items]
Restricted stock granted | shares	6,851,346
Value (per share) of restricted stock grant | $ / shares	$ 3.22
Equity award vesting percentage	33.33333%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

This regulatory filing also includes additional resources:
dnr-20160630x10q.pdf