DNR Denbury Resources Inc

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(1)

Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

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•	A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

•	A requirement to maintain a current ratio of 1.0 to 1.0.

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(1)	Ranges presented for fixed-price swaps and basis 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.

(3)	The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

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

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•

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 basis 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.

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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 September 30, 2017, instruments in this category include non-exchange-traded 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 $100 thousand in the fair value of these instruments as of September 30, 2017.

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•	Third quarter of 2016 results included a $75.5 million ($48.4 million net of tax) full cost pool ceiling test write-down of our oil and natural gas properties, offset in part by a $7.8 million gain on debt extinguishment.

•	Oil and natural gas revenues improved by $19.1 million, or 8%, in the third quarter of 2017, principally driven by a 10% improvement in realized oil prices, offset in part by a 2% decrease in average daily production volumes. Net realized oil price differentials improved by $1.23 per Bbl from the prior-year period.

•	Commodity derivatives expense increased by $46.5 million ($25.3 million of expense in the current-year period compared to $21.2 million of income in the prior-year period). This increase in expense was the result of losses from noncash fair value adjustments between the periods of $53.9 million, offset in part by a $7.4 million reduction in payments on derivative settlements.

•	Lease operating expenses increased by $11.2 million, or 11%, from the third quarter of 2016.

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•	Tax benefits of $8.6 million recognized in the current-year quarter related to enhanced oil recovery income tax credits.

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•	A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

•	A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

•	A requirement to maintain a current ratio of 1.0 to 1.0.

•	$135 million allocated for tertiary oil field expenditures;

•	$50 million allocated for other areas, primarily non-tertiary oil field expenditures;

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

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

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

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(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $75.5 million and $810.9 million for the three and nine months ended September 30, 2016, respectively.

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(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 gains (losses) 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 gains (losses) 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 $0.1 million for the three months ended September 30, 2017 and payments on settlements of $38.6 million for the nine months ended September 30, 2017, compared to payments on settlements of $7.3 million for the three months ended September 30, 2016 and receipts on settlements of $117.0 million for the nine months ended September 30, 2016. We believe that noncash fair value gains (losses) 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 period. 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 gains (losses) 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)	Represents production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017.

(3)	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, which closed in the third quarter of 2016, and other minor property divestitures.

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

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(1)	Averages are volume weighted.

(2)	If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and the sold put price.

(3)	The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the periods indicated.

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(1)

Cash interest is presented on an accrual basis, and includes the portion of interest on our 2021 Senior Secured Notes (interest on which is to be paid semiannually May 15 and November 15 of each year) versus the GAAP financial statement presentation in which interest on these notes is accounted for as debt and not reflected as interest for financial reporting purposes in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors.

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

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

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(1)	Shares purchased during the third quarter of 2017 were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted shares.

(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. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock as long as industry commodity pricing and general economic conditions persist. 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.

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*	Included herewith.

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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.

v3.8.0.1

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 31, 2017
Document And Company Information [Abstract]
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	DNR
Current Fiscal Year End Date	--12-31
Entity Central Index Key	0000945764
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	Denbury Resources Inc.
Entity Common Stock, Shares Outstanding		402,170,359

v3.8.0.1

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 57	$ 1,606
Accrued production receivable		121,346	124,936
Trade and other receivables, net		55,318	43,900
Derivative assets		60	0
Other current assets		10,811	10,684
Total current assets		187,592	181,126
Oil and natural gas properties (using full cost accounting)
Proved properties		10,694,674	10,419,827
Unevaluated properties		957,060	927,819
CO2 properties		1,190,190	1,188,467
Pipelines and plants		2,285,092	2,285,812
Other property and equipment		371,114	378,776
Less accumulated depletion, depreciation, amortization and impairment		(11,350,956)	(11,212,327)
Net property and equipment		4,147,174	3,988,374
Other assets		106,163	105,078
Total assets		4,440,929	4,274,578
Current liabilities
Accounts payable and accrued liabilities		183,063	200,266
Oil and gas production payable		69,737	80,585
Derivative liabilities		16,746	69,279
Current maturities of long-term debt (including future interest payable of $50,490 and $50,349, respectively - see Note 3)	[1]	85,002	83,366
Total current liabilities		354,548	433,496
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $153,196 and $178,476, respectively - see Note 3)		3,057,439	2,909,732
Asset retirement obligations		155,749	146,807
Derivative liabilities		4,263	0
Deferred tax liabilities, net		329,724	293,878
Other liabilities		21,759	22,217
Total long-term liabilities		3,568,934	3,372,634
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; 407,622,526 and 402,334,655 shares issued, respectively		408	402
Paid-in capital in excess of par		2,550,347	2,534,670
Accumulated deficit		(1,982,592)	(2,018,989)
Treasury stock, at cost, 5,382,584 and 3,906,877 shares, respectively		(50,716)	(47,635)
Total stockholders' equity		517,447	468,448
Total liabilities and stockholders' equity		$ 4,440,929	$ 4,274,578
[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

v3.8.0.1

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Current maturities of long-term debt	[1]	$ 85,002	$ 83,366
Long-term Debt and Capital Lease Obligations		$ 3,057,439	$ 2,909,732
Stockholders' equity
Preferred stock, par value (actual)		$ 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 (actual)		$ 0.001	$ 0.001
Common stock, shares authorized		600,000,000	600,000,000
Common stock, shares issued		407,622,526	402,334,655
Treasury stock, shares		5,382,584	3,906,877
Future interest payable on 9% Senior Secured Second Lien Notes
Debt Instrument [Line Items]
Current maturities of long-term debt		$ 50,490	$ 50,349
Long-term Debt and Capital Lease Obligations		$ 153,196	$ 178,476
[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

v3.8.0.1

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues and other income
Oil, natural gas, and related product sales	$ 259,030	$ 239,930	$ 776,088	$ 674,401
CO2 sales and transportation fees	6,590	6,253	18,533	19,147
Interest income and other income	939	7,802	8,576	10,429
Total revenues and other income	266,559	253,985	803,197	703,977
Expenses
Lease operating expenses	117,768	106,522	342,926	308,988
Marketing and plant operating expenses	11,816	14,452	39,758	40,645
CO2 discovery and operating expenses	1,346	861	2,452	2,539
Taxes other than income	20,233	20,401	62,848	59,997
General and administrative expenses	27,273	24,643	81,303	81,089
Interest, net of amounts capitalized of $9,416, $6,875, $22,217, and $18,944, respectively	24,546	24,778	75,785	103,007
Depletion, depreciation, and amortization	52,101	55,012	154,448	198,919
Commodity derivatives expense (income)	25,263	(21,224)	(9,712)	99,811
Gain on debt extinguishment	0	(7,826)	0	(115,095)
Write-down of oil and natural gas properties	0	75,521	0	810,921
Other expenses	0	0	0	36,232
Total expenses	280,346	293,140	749,808	1,627,053
Income (loss) before income taxes	(13,787)	(39,155)	53,389	(923,076)
Income tax provision (benefit)	(14,229)	(14,565)	17,018	(332,625)
Net income (loss)	$ 442	$ (24,590)	$ 36,371	$ (590,451)
Net income (loss) per common share
Basic	$ 0.00	$ (0.06)	$ 0.09	$ (1.60)
Diluted	$ 0.00	$ (0.06)	$ 0.09	$ (1.60)
Weighted average common shares outstanding
Basic	392,013	388,572	390,448	368,863
Diluted	393,023	388,572	392,625	368,863

v3.8.0.1

Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Expenses
Capitalized interest	$ 9,416	$ 6,875	$ 22,217	$ 18,944

v3.8.0.1

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities
Net income (loss)	$ 36,371	$ (590,451)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	154,448	198,919
Write-down of oil and natural gas properties	0	810,921
Deferred income taxes	35,846	(331,574)
Stock-based compensation	12,215	9,682
Commodity derivatives expense (income)	(9,712)	99,811
Receipt (payment) on settlements of commodity derivatives	(38,618)	116,958
Gain on debt extinguishment	0	(115,095)
Debt issuance costs and discounts	4,801	15,541
Other, net	(112)	(3,271)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	3,590	(2,207)
Trade and other receivables	(13,604)	35,911
Other current and long-term assets	(4,734)	(8,434)
Accounts payable and accrued liabilities	(22,736)	(57,830)
Oil and natural gas production payable	(10,848)	(13,290)
Other liabilities	(4,048)	(6,232)
Net cash provided by operating activities	142,859	159,359
Cash flows from investing activities
Oil and natural gas capital expenditures	(197,982)	(176,631)
Acquisitions of oil and natural gas properties	(91,124)	(560)
Net proceeds from sales of oil and natural gas properties and equipment	1,412	47,232
Other	(6,314)	(4,048)
Net cash used in investing activities	(294,008)	(134,007)
Cash flows from financing activities
Bank repayments	(1,188,000)	(1,362,500)
Bank borrowings	1,382,000	1,447,500
Interest payments on senior secured notes treated as a reduction of debt	(25,139)	0
Repurchases of senior subordinated notes	0	(76,708)
Pipeline financing and capital lease debt repayments	(20,523)	(21,510)
Other	1,262	(11,673)
Net cash provided by (used in) financing activities	149,600	(24,891)
Net increase (decrease) in cash and cash equivalents	(1,549)	461
Cash and cash equivalents at beginning of period	1,606	2,812
Cash and cash equivalents at end of period	$ 57	$ 3,273

v3.8.0.1

Basis of Presentation	9 Months Ended
	Sep. 30, 2017
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, 2016 (the “Form 10-K”).  Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year.  In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2017, our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and our consolidated cash flows for the nine months ended September 30, 2017 and 2016. Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity. Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   392,013   388,572   390,448   368,863 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,010   —   2,177   — Diluted weighted average common shares outstanding   393,023   388,572   392,625   368,863 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,551   6,091   4,793   6,590 Restricted stock and performance-based equity awards   9,891   9,178   6,259   6,053 2016 Write-Down of Oil and Natural Gas Properties Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing full cost pool ceiling test write-downs of $75.5 million, $479.4 million, and $256.0 million during the three months ended September 30, June 30 and March 31, 2016, respectively. We have not recorded a ceiling test write-down during the first nine months of 2017. Recent Accounting Pronouncements Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows. 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. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.

v3.8.0.1

Asset Acquisition and Assets Held for Sale	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
Asset Acquisition	Note 2. Asset Acquisition and Assets Held for Sale Asset Acquisition On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $71.5 million, before customary closing adjustments. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties. Assets Held for Sale We began actively marketing for sale certain non-productive surface acreage in the Houston area during July 2017, which we currently anticipate selling during 2018. As of September 30, 2017, the carrying value of the land held for sale was $33.1 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.

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Long-Term Debt	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Note 3. Long-Term Debt The following long-term debt and capital lease obligations were outstanding as of the dates indicated:     September 30,   December 31, In thousands   2017   2016 Senior Secured Bank Credit Agreement   $ 495,000   $ 301,000 9% Senior Secured Second Lien Notes due 2021   614,919   614,919 6⅜% Senior Subordinated Notes due 2021   215,144   215,144 5½% Senior Subordinated Notes due 2022   772,912   772,912 4⅝% Senior Subordinated Notes due 2023   622,297   622,297 Other Subordinated Notes, including premium of $1 and $3, respectively   2,251   2,253 Pipeline financings   195,258   202,671 Capital lease obligations   34,542   48,718 Total debt principal balance   2,952,323   2,779,914 Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)   203,686   228,825 Issuance costs on senior secured second lien and senior subordinated notes   (13,568 )   (15,641 ) Total debt, net of debt issuance costs   3,142,441   2,993,098 Less: current maturities of long-term debt (1)   (85,002 )   (83,366 ) Long-term debt and capital lease obligations   $ 3,057,439   $ 2,909,732 (1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months. The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding 2021 Senior Secured Notes and our senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries. Senior Secured Bank Credit Facility In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019 and semiannual borrowing base redeterminations in May and November of each year. As part of our fall 2017 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with the next such redetermination scheduled for May 2018. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding under the Bank Credit Agreement was 4.3% as of September 30, 2017. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement. In May 2017, we entered into a Fourth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to amend certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased the applicable margin for ABR Loans and LIBOR Loans by 50 basis points, such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum. In November 2017, we entered into a Fifth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we can incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time. The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following: • A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio; • A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and • A requirement to maintain a current ratio of 1.0 to 1.0. The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC. 2016 Senior Subordinated Notes Exchange During May 2016, in privately negotiated transactions, we exchanged a total of $1,057.8 million of our existing senior subordinated notes for $614.9 million principal amount of our 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. As a result of this debt exchange, we recognized a gain of $12.0 million during the nine months ended September 30, 2016, which is included in “Gain on debt extinguishment” in the accompanying Consolidated Statements of Operations. 2016 Repurchases of Senior Subordinated Notes During the first and third quarters of 2016, we repurchased a total of $181.9 million of our outstanding long-term indebtedness in open-market transactions for a total purchase price of $76.7 million, excluding accrued interest. In connection with these transactions, we recognized a $103.1 million gain on extinguishment, net of unamortized debt issuance costs written off, during the nine months ended September 30, 2016. As of November 6, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on open market or other repurchases or redemptions of our senior subordinated notes.

v3.8.0.1

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Note 4. 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. Our income taxes are based on an estimated statutory rate of approximately 38% in 2017 and 2016. Our effective tax rate for the three months ended September 30, 2017, differed from our estimated statutory rate, primarily due to the impact of recognizing a tax benefit of $8.6 million in the current quarter for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall (tax deduction less than book expense) of $2.1 million. With pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these items had a significant impact on the current quarter’s effective tax rate.

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Commodity Derivative Contracts	9 Months Ended
	Sep. 30, 2017
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, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2017, 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 September 30, 2017, 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:                               2017 Fixed-Price Swaps                               Oct – Dec   NYMEX   12,000   $ 48.40 – 50.13   $ 49.76   $ —   $ —   $ — 2017 Three-Way Collars (2)                               Oct – Dec   NYMEX   14,000   $ 40.00 – 70.20   $ —   $ 31.07   $ 41.07   $ 65.79 Oct – Dec   LLS   1,000     41.00 – 70.25   —   31.00   41.00   70.25 2017 Collars                                   Oct – Dec   NYMEX   1,000   $ 40.00 – 70.00   $ —   $ —   $ 40.00   $ 70.00 2018 Fixed-Price Swaps                               Jan – Dec   NYMEX   15,500   $ 50.00 – 50.40   $ 50.13   $ —   $ —   $ — 2018 Three-Way Collars (2)                               Jan – Dec   NYMEX   15,000   $ 45.00 – 56.60   $ —   $ 36.50   $ 46.50   $ 53.88                                                                         2017 Basis Swaps (3)                               Dec   Argus LLS   5,000   $ 4.15 – 4.15   $ 4.15   $ —   $ —   $ — 2018 Basis Swaps (3)                               Jan – June   Argus LLS   2,500   $ 3.13 – 3.15   $ 3.13   $ —   $ —   $ — (1) Ranges presented for fixed-price swaps and basis 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. (3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

v3.8.0.1

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
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 basis 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 September 30, 2017, instruments in this category include non-exchange-traded 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 $100 thousand in the fair value of these instruments as of September 30, 2017. 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 September 30, 2017                 Assets                 Oil derivative contracts – current   $ —   $ 58   $ 2   $ 60 Total Assets   $ —   $ 58   $ 2   $ 60                   Liabilities                 Oil derivative contracts – current   $ —   $ (16,746 )   $ —   $ (16,746 ) Oil derivative contracts – long-term   —   (4,263 )   —   (4,263 ) Total Liabilities   $ —   $ (21,009 )   $ —   $ (21,009 )                   December 31, 2016                 Liabilities                 Oil derivative contracts – current   $ —   $ (68,753 )   $ (526 )   $ (69,279 ) Total Liabilities   $ —   $ (68,753 )   $ (526 )   $ (69,279 ) 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 nine months ended September 30, 2017 and 2016:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Fair value of Level 3 instruments, beginning of period   $ 99   $ 240   $ (526 )   $ 52,834 Fair value gains (losses) on commodity derivatives   (97 )   2,402   528   (2,134 ) Receipts on settlements of commodity derivatives   —   (3,167 )   —   (51,225 ) Fair value of Level 3 instruments, end of period   $ 2   $ (525 )   $ 2   $ (525 )                   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   $ (71 )   $ 891   $ 54   $ (525 ) 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 9/30/2017 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 2   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017   15.4% – 33.4% 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 2021 Senior Secured Notes and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of September 30, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $1,996.6 million and $2,327.8 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

v3.8.0.1

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 7. Commitments and Contingencies Commitments The Company has a CO2 offtake agreement with Mississippi Power Company (“MSPC”), providing for our purchase of CO2 generated as a byproduct of the gasification portion of their Kemper County energy facility. After receiving minor amounts of CO2 from the facility during the first half of 2017, in June 2017, MSPC announced the immediate and indefinite suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility. As a result of this suspension, the Company is not expecting to receive any CO2 from this facility for the foreseeable future. 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. Riley Ridge Helium Supply Contract Claim As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility.  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are capped at $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium to the third-party purchaser under the helium supply contract.  In a case originally filed in November 2014 by APMTG Helium, LLC, the third-party helium purchaser, after a week of trial during February 2017 on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed until November 27, 2017. The Company plans to continue to vigorously defend its position and pursue its claim, but we are unable to predict at this time the outcome of this dispute.

v3.8.0.1

Additional Balance Sheet Details	9 Months Ended
	Sep. 30, 2017
Disclosure Text Block [Abstract]
Additional Balance Sheet Details	Note 8. Additional Balance Sheet Details Trade and Other Receivables, Net     September 30,   December 31, In thousands   2017   2016 Trade accounts receivable, net   $ 15,319   $ 20,084 Federal income tax receivable   11,687   — Other receivables   28,312   23,816 Total   $ 55,318   $ 43,900

v3.8.0.1

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2017
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, 2016 (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 September 30, 2017, our consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and our consolidated cash flows for the nine months ended September 30, 2017 and 2016
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Net Income (Loss) per Common Share	Net Income (Loss) per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period.  Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.  Potentially dilutive securities consist of nonvested restricted stock and nonvested performance-based equity awards.  For the three and nine months ended September 30, 2017 and 2016, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share. The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   392,013   388,572   390,448   368,863 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,010   —   2,177   — Diluted weighted average common shares outstanding   393,023   388,572   392,625   368,863 Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period. The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,551   6,091   4,793   6,590 Restricted stock and performance-based equity awards   9,891   9,178   6,259   6,053
Oil and Natural Gas Properties Policy	2016 Write-Down of Oil and Natural Gas Properties Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period ended as of each quarterly reporting period. The falling prices in 2016, relative to 2015 prices, led to our recognizing full cost pool ceiling test write-downs of $75.5 million, $479.4 million, and $256.0 million during the three months ended September 30, June 30 and March 31, 2016, respectively. We have not recorded a ceiling test write-down during the first nine months of 2017.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations: Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Effective January 1, 2017, we adopted ASU 2017-01. See Note 2, Asset Acquisition and Assets Held for Sale, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. Management does not currently expect that the adoption of ASU 2016-18 will have a material impact on our consolidated financial statements, other than the inclusion of restricted cash on our consolidated statements of cash flows. 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. We expect to adopt this standard using the modified retrospective method upon its effective date. Management is currently finishing the evaluation of our various revenue contracts. However, based on the work performed to date, we do not believe this standard will have a material impact on our consolidated financial statements, but will require enhanced footnote disclosures.
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, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2017, 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 basis 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 September 30, 2017, instruments in this category include non-exchange-traded 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 $100 thousand in the fair value of these instruments as of September 30, 2017. 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.

v3.8.0.1

Basis of Presentation (Tables)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Weighted average shares used in the basic and diluted net income (loss) per common share	The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   392,013   388,572   390,448   368,863 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,010   —   2,177   — Diluted weighted average common shares outstanding   393,023   388,572   392,625   368,863
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,551   6,091   4,793   6,590 Restricted stock and performance-based equity awards   9,891   9,178   6,259   6,053

v3.8.0.1

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Components of Long-Term Debt	The following long-term debt and capital lease obligations were outstanding as of the dates indicated:     September 30,   December 31, In thousands   2017   2016 Senior Secured Bank Credit Agreement   $ 495,000   $ 301,000 9% Senior Secured Second Lien Notes due 2021   614,919   614,919 6⅜% Senior Subordinated Notes due 2021   215,144   215,144 5½% Senior Subordinated Notes due 2022   772,912   772,912 4⅝% Senior Subordinated Notes due 2023   622,297   622,297 Other Subordinated Notes, including premium of $1 and $3, respectively   2,251   2,253 Pipeline financings   195,258   202,671 Capital lease obligations   34,542   48,718 Total debt principal balance   2,952,323   2,779,914 Future interest payable on 9% Senior Secured Second Lien Notes due 2021 (1)   203,686   228,825 Issuance costs on senior secured second lien and senior subordinated notes   (13,568 )   (15,641 ) Total debt, net of debt issuance costs   3,142,441   2,993,098 Less: current maturities of long-term debt (1)   (85,002 )   (83,366 ) Long-term debt and capital lease obligations   $ 3,057,439   $ 2,909,732 (1) Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

v3.8.0.1

Commodity Derivative Contracts (Tables)	9 Months Ended
	Sep. 30, 2017
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 September 30, 2017, 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:                               2017 Fixed-Price Swaps                               Oct – Dec   NYMEX   12,000   $ 48.40 – 50.13   $ 49.76   $ —   $ —   $ — 2017 Three-Way Collars (2)                               Oct – Dec   NYMEX   14,000   $ 40.00 – 70.20   $ —   $ 31.07   $ 41.07   $ 65.79 Oct – Dec   LLS   1,000     41.00 – 70.25   —   31.00   41.00   70.25 2017 Collars                                   Oct – Dec   NYMEX   1,000   $ 40.00 – 70.00   $ —   $ —   $ 40.00   $ 70.00 2018 Fixed-Price Swaps                               Jan – Dec   NYMEX   15,500   $ 50.00 – 50.40   $ 50.13   $ —   $ —   $ — 2018 Three-Way Collars (2)                               Jan – Dec   NYMEX   15,000   $ 45.00 – 56.60   $ —   $ 36.50   $ 46.50   $ 53.88                                                                         2017 Basis Swaps (3)                               Dec   Argus LLS   5,000   $ 4.15 – 4.15   $ 4.15   $ —   $ —   $ — 2018 Basis Swaps (3)                               Jan – June   Argus LLS   2,500   $ 3.13 – 3.15   $ 3.13   $ —   $ —   $ — (1) Ranges presented for fixed-price swaps and basis 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. (3) The basis swap contracts establish a fixed amount for the differential between Argus WTI and Argus LLS prices on a trade-month basis for the period indicated.

v3.8.0.1

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
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 September 30, 2017                 Assets                 Oil derivative contracts – current   $ —   $ 58   $ 2   $ 60 Total Assets   $ —   $ 58   $ 2   $ 60                   Liabilities                 Oil derivative contracts – current   $ —   $ (16,746 )   $ —   $ (16,746 ) Oil derivative contracts – long-term   —   (4,263 )   —   (4,263 ) Total Liabilities   $ —   $ (21,009 )   $ —   $ (21,009 )                   December 31, 2016                 Liabilities                 Oil derivative contracts – current   $ —   $ (68,753 )   $ (526 )   $ (69,279 ) Total Liabilities   $ —   $ (68,753 )   $ (526 )   $ (69,279 )
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 nine months ended September 30, 2017 and 2016:     Three Months Ended   Nine Months Ended     September 30,   September 30, In thousands   2017   2016   2017   2016 Fair value of Level 3 instruments, beginning of period   $ 99   $ 240   $ (526 )   $ 52,834 Fair value gains (losses) on commodity derivatives   (97 )   2,402   528   (2,134 ) Receipts on settlements of commodity derivatives   —   (3,167 )   —   (51,225 ) Fair value of Level 3 instruments, end of period   $ 2   $ (525 )   $ 2   $ (525 )                   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   $ (71 )   $ 891   $ 54   $ (525 )
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 9/30/2017 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 2   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2017   15.4% – 33.4%

v3.8.0.1

Additional Balance Sheet Details (Tables)	9 Months Ended
	Sep. 30, 2017
Table Text Block [Abstract]
Trade and Other Receivables, Net	Trade and Other Receivables, Net     September 30,   December 31, In thousands   2017   2016 Trade accounts receivable, net   $ 15,319   $ 20,084 Federal income tax receivable   11,687   — Other receivables   28,312   23,816 Total   $ 55,318   $ 43,900

v3.8.0.1

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Weighted average shares used in the basic and diluted net income (loss) per common share
Basic weighted average common shares outstanding	392,013	388,572	390,448	368,863
Potentially dilutive securities
Restricted stock and performance-based equity awards	1,010	0	2,177	0
Diluted weighted average common shares outstanding	393,023	388,572	392,625	368,863

v3.8.0.1

Basis of Presentation (Antidilutive Securities) (Details) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Stock appreciation rights
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	4,551	6,091	4,793	6,590
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	9,891	9,178	6,259	6,053

v3.8.0.1

Basis of Presentation (Details Textuals) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Write-down of oil and natural gas properties	$ 0	$ 75,521	$ 479,400	$ 256,000	$ 0	$ 810,921

v3.8.0.1

Asset Acquisition and Assets Held for Sale (Details Textuals) - USD ($) $ in Millions	Jun. 30, 2017	Sep. 30, 2017
Business Combinations [Abstract]
Non-operated working interest acquired in asset acquisition	23.00%
Costs Incurred, Acquisition of Oil and Gas Properties	$ 71.5
Land Available-for-sale		$ 33.1

v3.8.0.1

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016	May 31, 2016
Debt Instrument [Line Items]
Senior Secured Bank Credit Agreement		$ 495,000	$ 301,000
Pipeline financings		195,258	202,671
Capital lease obligations		34,542	48,718
Total debt principal balance		2,952,323	2,779,914
Future interest payable on 9% Senior Secured Second Lien Notes due 2021	[1]	203,686	228,825
Total debt, net of debt issuance costs		3,142,441	2,993,098
Less: current maturities of long-term debt	[1]	(85,002)	(83,366)
Long-term debt and capital lease obligations		3,057,439	2,909,732
9% Senior Secured Second Lien Notes Due 2021
Debt Instrument [Line Items]
9% Senior Secured Second Lien Notes due 2021		614,919	614,919	$ 614,919
Less: current maturities of long-term debt		$ (50,490)
Debt Instrument, Interest Rate, Stated Percentage		9.00%
Second Lien and Senior Subordinated Notes
Debt Instrument [Line Items]
Issuance costs on senior secured second lien and senior subordinated notes		$ (13,568)	(15,641)
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 215,144	215,144
Debt Instrument, Interest Rate, Stated Percentage		6.375%
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 772,912	772,912
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 622,297	622,297
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Senior Subordinated Notes | Other Subordinated Notes
Debt Instrument [Line Items]
Senior Subordinated Notes		$ 2,251	2,253
Including premium of		$ 1	$ 3
[1] Future interest payable on our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) 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 September 30, 2017 include $50.5 million of future interest payable related to the 2021 Senior Secured Notes that is due within the next twelve months.

v3.8.0.1

Long-Term Debt (Details Textuals)	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2016 USD ($) shares	Sep. 30, 2017 USD ($) shares	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) shares	Sep. 30, 2016 USD ($)	Nov. 06, 2017 USD ($)	Nov. 01, 2017 USD ($)	Dec. 31, 2016 shares
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%		100.00%
Debt Instrument, Repurchased Face Amount			$ 181,900,000		$ 181,900,000
Debt Instrument, Repurchase Amount			76,700,000		76,700,000
Gain on debt extinguishment		$ 0	$ 7,826,000	$ 0	115,095,000
Debt Conversion, Original Debt, Amount	$ 1,057,800,000
Common Stock, Shares, Issued | shares	40,700,000	407,622,526		407,622,526				402,334,655
Extinguishment of Debt, Amount	$ 442,900,000
Senior Secured Bank Credit Facility [Abstract]
Weighted average interest rate on Bank Credit Facility		4.30%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.50%
Current Ratio Requirement				1.0
Maximum Incurrence of Junior Lien Debt Permitted		$ 1,000,000,000		$ 1,000,000,000
Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Line of Credit, Borrowing Base							$ 1,050,000,000.00
Line of Credit Facility, Current Borrowing Capacity							$ 1,050,000,000.00
Maximum Incurrence of Junior Lien Debt Permitted						$ 1,200,000,000
Senior subordinated notes available for repurchase or other redemptions						$ 148,300,000
Notes Exchange [Member]
Long Term Debt (Textuals) [Abstract]
Gain on debt extinguishment					12,000,000
Senior Subordinated Notes
Long Term Debt (Textuals) [Abstract]
Gain on debt extinguishment					$ 103,100,000
Year 2017 | Q4
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		3.0
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2018 | Q1
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		3.0
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2018 | Q2
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2018 | Q3
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2018 | Q4
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2019 | Q1
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2019 | Q2
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Year 2019 | Q3
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		2.5
Consolidated EBITDAX to Consolidated Interest Charges		1.25
Base Rate [Member] | Minimum | Senior Secured Bank Credit Facility
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility		1.50%
Base Rate [Member] | Maximum | Senior Secured Bank Credit Facility
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility		2.50%
London Interbank Offered Rate (LIBOR) [Member] | Minimum | Senior Secured Bank Credit Facility
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility		2.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum | Senior Secured Bank Credit Facility
Senior Secured Bank Credit Facility [Abstract]
Interest rate margins on Senior Secured Bank Credit Facility		3.50%

v3.8.0.1

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Statutory rate		38.00%	38.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount	$ 8.6
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount	$ 2.1

v3.8.0.1

Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details)	Sep. 30, 2017 bbl / d $ / Barrel
Swap | Year 2017 | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	12,000
Weighted average swap price	49.76
Swap | Year 2017 | Q4 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	48.40
Swap | Year 2017 | Q4 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	50.13
Swap | Year 2018 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	15,500
Weighted average swap price	50.13
Swap | Year 2018 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	50.00
Swap | Year 2018 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	50.40
Three-way Collar | Year 2017 | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	14,000
Derivative, Floor Price	40.00
Derivative, Cap Price	70.20
Weighted average sold put price	31.07
Weighted average floor price	41.07
Weighted average ceiling price	65.79
Three-way Collar | Year 2017 | Q4 | LLS
Derivative [Line Items]
Volume per day | bbl / d	1,000
Derivative, Floor Price	41.00
Derivative, Cap Price	70.25
Weighted average sold put price	31.00
Weighted average floor price	41.00
Weighted average ceiling price	70.25
Three-way Collar | Year 2018 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	15,000
Derivative, Floor Price	45.00
Derivative, Cap Price	56.60
Weighted average sold put price	36.50
Weighted average floor price	46.50
Weighted average ceiling price	53.88
Collar | Year 2017 | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	1,000
Derivative, Floor Price	40.00
Derivative, Cap Price	70.00
Weighted average floor price	40.00
Weighted average ceiling price	70.00
Basis Swap | Year 2017 | December | LLS
Derivative [Line Items]
Volume per day | bbl / d	5,000
Weighted average swap price	4.15
Basis Swap | Year 2017 | December | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	4.15
Basis Swap | Year 2017 | December | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	4.15
Basis Swap | Year 2018 | Q1-Q2 | LLS
Derivative [Line Items]
Volume per day | bbl / d	2,500
Weighted average swap price	3.13
Basis Swap | Year 2018 | Q1-Q2 | LLS | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	3.13
Basis Swap | Year 2018 | Q1-Q2 | LLS | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	3.15

v3.8.0.1

Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	$ 60	$ 0
Total Assets	60
Oil derivative contracts - current liability	(16,746)	(69,279)
Oil derivative contracts - long-term liabilities	(4,263)	0
Total Liabilities	(21,009)	(69,279)
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
Total Assets	0
Oil derivative contracts - current liability	0	0
Oil derivative contracts - long-term liabilities	0
Total Liabilities	0	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	58
Total Assets	58
Oil derivative contracts - current liability	(16,746)	(68,753)
Oil derivative contracts - long-term liabilities	(4,263)
Total Liabilities	(21,009)	(68,753)
Significant Unobservable Inputs (Level 3)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	2
Total Assets	2
Oil derivative contracts - current liability	0	(526)
Oil derivative contracts - long-term liabilities	0
Total Liabilities	$ 0	$ (526)

v3.8.0.1

Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value of Level 3 instruments, beginning of period	$ 99	$ 240	$ (526)	$ 52,834
Fair value gains (losses) on commodity derivatives	(97)	2,402	528	(2,134)
Receipts on settlements of commodity derivatives	0	(3,167)	0	(51,225)
Fair value of Level 3 instruments, end of period	2	(525)	2	(525)
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	$ (71)	$ 891	$ 54	$ (525)

v3.8.0.1

Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ 2	$ 99	$ (526)	$ (525)	$ 240	$ 52,834
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	$ 2
Income Approach Valuation Technique | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	15.40%
Income Approach Valuation Technique | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	33.40%

v3.8.0.1

Fair Value Measurements (Details Textuals) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Sensitivity Analysis of Fair Value, Impact of 100 Basis Point Increase or Decrease in Level 3 Inputs	$ 100
Debt, Fair Value	$ 1,996,600	$ 2,327,800

v3.8.0.1

Commitments and Contingencies (Details) - Helium Supply Arrangement [Member] $ in Millions	3 Months Ended
	Sep. 30, 2017 USD ($)
Long-term Purchase Commitment [Line Items]
Term of Long Term Supply Arrangement	20 years
Maximum Annual Payment In Event Of Shortfall	$ 8.0
Maximum Payment In Event Of Shortfall	$ 46.0

v3.8.0.1

Additional Balance Sheet Details (Trade and Other Receivables, Net Table) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Receivables [Abstract]
Trade accounts receivable, net	$ 15,319	$ 20,084
Federal income tax receivable	11,687	0
Other receivables	28,312	23,816
Total	$ 55,318	$ 43,900

This regulatory filing also includes additional resources:
dnr-2017093010q.pdf