DNR Denbury Resources Inc

---

---

---

---

---

---

---

(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 June 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.

---

•	Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;

•	Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, 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;

•	Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and

•	Increasing 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.

---

---

(1)	Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2)

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

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

•

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

---

•

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 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 $9 thousand in the fair value of these instruments as of June 30, 2017.

---

---

---

---

---

•	Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility;

•	Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, 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;

•	Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and

•	Increasing 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.

•	$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

•	$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.

---

---

(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $479.4 million and $735.4 million for the three and six months ended June 30, 2016, respectively.

---

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

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

(4)

Noncash fair value 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 payments on settlements of $11.8 million and $38.7 million for the three and six months ended June 30, 2017, respectively, compared to receipts on settlements of $52.0 million and $124.3 million for the three and six months ended June 30, 2016, respectively. 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.

---

(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.

---

---

(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.

---

(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.

---

---

(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.

---

---

---

(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.

---

---

---

---

---

---

(1)	Stock repurchases during the second quarter of 2017 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted and performance 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.

---

*	Included herewith.

---

---

---

(g)

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

---

---

---

---

(a)	[one year anniversary of the Date of Grant];

(b)	the date of Holder’s death or Disability;

(c)	the date of a Change of Control; and

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

---

---

---

---

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.

v3.7.0.1

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 31, 2017
Document And Company Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
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		403,045,927

v3.7.0.1

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 3,508	$ 1,606
Accrued production receivable		103,822	124,936
Trade and other receivables, net		60,393	43,900
Derivative assets		3,572	0
Other current assets		14,934	10,684
Total current assets		186,229	181,126
Oil and natural gas properties (using full cost accounting)
Proved properties		10,631,368	10,419,827
Unevaluated properties		954,189	927,819
CO2 properties		1,188,555	1,188,467
Pipelines and plants		2,285,841	2,285,812
Other property and equipment		371,886	378,776
Less accumulated depletion, depreciation, amortization and impairment		(11,302,655)	(11,212,327)
Net property and equipment		4,129,184	3,988,374
Derivative assets		1,237	0
Other assets		108,691	105,078
Total assets		4,425,341	4,274,578
Current liabilities
Accounts payable and accrued liabilities		177,950	200,266
Oil and gas production payable		67,933	80,585
Derivative liabilities		0	69,279
Current maturities of long-term debt (including future interest payable of $50,490 and $50,349, respectively - see Note 3)	[1]	83,458	83,366
Total current liabilities		329,341	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)		3,060,048	2,909,732
Asset retirement obligations		154,454	146,807
Derivative liabilities		407	0
Deferred tax liabilities, net		345,025	293,878
Other liabilities		21,867	22,217
Total long-term liabilities		3,581,801	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; 403,305,493 and 402,334,655 shares issued, respectively		403	402
Paid-in capital in excess of par		2,546,102	2,534,670
Accumulated deficit		(1,983,056)	(2,018,989)
Treasury stock, at cost, 4,405,555 and 3,906,877 shares, respectively		(49,250)	(47,635)
Total stockholders' equity		514,199	468,448
Total liabilities and stockholders' equity		$ 4,425,341	$ 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 June 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.

v3.7.0.1

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Current maturities of long-term debt	[1]	$ 83,458	$ 83,366
Long-term Debt and Capital Lease Obligations		$ 3,060,048	$ 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		403,305,493	402,334,655
Treasury stock, shares		4,405,555	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 June 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.

v3.7.0.1

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues and other income
Oil, natural gas, and related product sales	$ 250,880	$ 246,668	$ 517,058	$ 434,471
CO2 sales and transportation fees	6,555	6,622	11,943	12,894
Interest income and other income	3,749	1,858	7,637	2,627
Total revenues and other income	261,184	255,148	536,638	449,992
Expenses
Lease operating expenses	111,318	100,019	225,158	202,466
Marketing and plant operating expenses	13,877	12,999	27,942	26,193
CO2 discovery and operating expenses	513	1,071	1,106	1,678
Taxes other than income	20,175	19,504	42,615	39,596
General and administrative expenses	25,789	22,545	54,030	56,446
Interest, net of amounts capitalized of $8,147, $6,289, $12,801 and $12,069, respectively	24,061	36,058	51,239	78,229
Depletion, depreciation, and amortization	51,152	66,541	102,347	143,907
Commodity derivatives expense (income)	(10,373)	98,209	(34,975)	121,035
Gain on debt extinguishment	0	(12,278)	0	(107,269)
Write-down of oil and natural gas properties	0	479,400	0	735,400
Other expenses	0	34,688	0	36,232
Total expenses	236,512	858,756	469,462	1,333,913
Income (loss) before income taxes	24,672	(603,608)	67,176	(883,921)
Income tax provision (benefit)	10,273	(222,940)	31,247	(318,060)
Net income (loss)	$ 14,399	$ (380,668)	$ 35,929	$ (565,861)
Net income (loss) per common share
Basic	$ 0.04	$ (1.03)	$ 0.09	$ (1.58)
Diluted	$ 0.04	$ (1.03)	$ 0.09	$ (1.58)
Weighted average common shares outstanding
Basic	389,904	370,566	389,652	358,901
Diluted	391,827	370,566	392,414	358,901

v3.7.0.1

Condensed Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Expenses
Capitalized interest	$ 8,147	$ 6,289	$ 12,801	$ 12,069

v3.7.0.1

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash flows from operating activities
Net income (loss)	$ 35,929	$ (565,861)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	102,347	143,907
Write-down of oil and natural gas properties	0	735,400
Deferred income taxes	51,147	(318,055)
Stock-based compensation	8,941	4,122
Commodity derivatives expense (income)	(34,975)	121,035
Receipt (payment) on settlements of commodity derivatives	(38,707)	124,253
Gain on debt extinguishment	0	(107,269)
Debt issuance costs and discounts	3,344	14,072
Other, net	(1,006)	(1,743)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	21,114	(20,060)
Trade and other receivables	(17,916)	17,568
Other current and long-term assets	(10,225)	(7,974)
Accounts payable and accrued liabilities	(26,611)	(71,830)
Oil and natural gas production payable	(12,652)	(3,624)
Other liabilities	(3,522)	(997)
Net cash provided by operating activities	77,208	62,944
Cash flows from investing activities
Oil and natural gas capital expenditures	(129,884)	(126,302)
Acquisitions of oil and natural gas properties	(89,208)	(904)
Other	(2,058)	(314)
Net cash used in investing activities	(221,150)	(127,520)
Cash flows from financing activities
Bank repayments	(796,000)	(994,000)
Bank borrowings	985,000	1,139,000
Interest payments on senior secured notes treated as a reduction of debt	(25,139)	0
Repurchases of senior subordinated notes	0	(55,521)
Pipeline financing and capital lease debt repayments	(13,728)	(14,336)
Other	(4,289)	(10,834)
Net cash provided by financing activities	145,844	64,309
Net increase (decrease) in cash and cash equivalents	1,902	(267)
Cash and cash equivalents at beginning of period	1,606	2,812
Cash and cash equivalents at end of period	$ 3,508	$ 2,545

v3.7.0.1

Basis of Presentation	6 Months Ended
	Jun. 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 June 30, 2017, our consolidated results of operations for the three and six months ended June 30, 2017 and 2016, and our consolidated cash flows for the six months ended June 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 six months ended June 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   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   389,904   370,566   389,652   358,901 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,923   —   2,762   — Diluted weighted average common shares outstanding   391,827   370,566   392,414   358,901 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 six months ended June 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   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,785   6,265   4,914   6,839 Restricted stock and performance-based equity awards   7,655   4,374   4,442   4,491 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 $479.4 million and $256.0 million during the three months ended June 30 and March 31, 2016, respectively. We did not record a ceiling test write-down during the three or six months ended June 30, 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, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. 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 in the process of reviewing our various revenue contracts to determine the impact of adoption of this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.

v3.7.0.1

Asset Acquisition	6 Months Ended
	Jun. 30, 2017
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Asset Acquisition	Note 2. 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.

v3.7.0.1

Long-Term Debt	6 Months Ended
	Jun. 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:     June 30,   December 31, In thousands   2017   2016 Senior Secured Bank Credit Agreement   $ 490,000   $ 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 $2 and $3, respectively   2,252   2,253 Pipeline financings   197,726   202,671 Capital lease obligations   38,829   48,718 Total debt principal balance   2,954,079   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   (14,259 )   (15,641 ) Total debt, net of debt issuance costs   3,143,506   2,993,098 Less: current maturities of long-term debt (1)   (83,458 )   (83,366 ) Long-term debt and capital lease obligations   $ 3,060,048   $ 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 June 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 (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2019. In May 2017, as part of our 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 November 2017. 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 4.2% as of June 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 conjunction with the May 2017 borrowing base redetermination, we amended 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. The amendments to the Bank Credit Agreement included the following: • Eliminating the consolidated total net debt to consolidated EBITDAX covenants that were scheduled to go into effect starting in 2018 through the remaining term of the facility; • Extending the existing consolidated senior secured debt to consolidated EBITDAX covenant through the remaining term of the facility, 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; • Extending the existing minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0 through the remaining term of the facility, as it previously would have expired after the fourth quarter of 2017; and • Increasing 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. The requirement to maintain a current ratio of 1.0 to 1.0 was not amended, and so remains in place. Also, incurrence of additional debt (separate from debt under the credit facility) in connection with various events remains subject to a Total Leverage Test unless the consolidated total net debt to EBITDAX ratio is reduced on a pro forma basis by the event. All of the above descriptions of our Bank Credit Agreement and the amendments thereto are qualified by the express language and defined terms contained in the Bank Credit Agreement and the Fourth Amendment to the Bank Credit Agreement dated May 3, 2017, 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. The exchanged notes consisted of $175.1 million principal amount of our 6⅜% Senior Subordinated Notes due 2021 (“2021 Notes”), $411.0 million principal amount of our 5½% Senior Subordinated Notes due 2022 (“2022 Notes”), and $471.7 million principal amount of our 4⅝% Senior Subordinated Notes due 2023 (“2023 Notes”). As a result of this debt exchange, we recognized a gain of $12.3 million during the three months ended June 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 quarter of 2016, we repurchased a total of $152.3 million of our outstanding long-term indebtedness, consisting of $4.0 million principal amount of our 2021 Notes, $42.3 million principal amount of our 2022 Notes, and $106.0 million principal amount of our 2023 Notes in open-market transactions for a total purchase price of $55.5 million, excluding accrued interest. In connection with these transactions, we recognized a $95.0 million gain on extinguishment, net of unamortized debt issuance costs written off, during the three months ended March 31, 2016. As of August 7, 2017, under the Bank Credit Agreement, up to an additional $148.3 million may be spent on repurchases or other redemptions of our senior subordinated notes.

v3.7.0.1

Income Taxes	6 Months Ended
	Jun. 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. As of June 30, 2017, we had $36.5 million of deferred tax assets associated with State of Louisiana net operating losses. As the result of falling commodity prices, combined with a new tax law enacted in the State of Louisiana effective June 30, 2015, which limits a company’s utilization of certain deductions, including our net operating loss carryforwards, we recognized tax valuation allowances totaling $36.5 million during 2015 and 2016, which reduced the carrying value of these deferred tax assets to zero as of December 31, 2016. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. As of June 30, 2017, we had an unrecognized tax benefit of $5.4 million related to an uncertain tax position. The unrecognized tax benefit was recorded during 2015 as a direct reduction of the associated deferred tax asset and, if recognized, would not materially affect our annual effective tax rate. The tax benefit from an uncertain tax position will only be recognized if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. We currently do not expect a material change to the uncertain tax position within the next 12 months. Our policy is to recognize penalties and interest related to uncertain tax positions in income tax expense; however, no such amounts were accrued related to the uncertain tax position as of June 30, 2017.

v3.7.0.1

Commodity Derivative Contracts	6 Months Ended
	Jun. 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 and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, 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 June 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 Three-Way Collars (2)                               July – Sept   NYMEX   14,500   $ 40.00 – 70.25   $ —   $ 30.00   $ 40.00   $ 69.09 July – Sept   LLS   2,000     41.00 – 69.25   —   31.00   41.00   69.25 Oct – Dec   NYMEX   11,000     40.00 – 70.20   —   30.00   40.00   69.67 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   3,000   $ 50.12 – 50.25   $ 50.20   $ —   $ —   $ — 2018 Three-Way Collars (2)                               Jan – Dec   NYMEX   6,000   $ 45.00 – 56.60   $ —   $ 36.25   $ 46.25   $ 55.08 (1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

v3.7.0.1

Fair Value Measurements	6 Months Ended
	Jun. 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 fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 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 $9 thousand in the fair value of these instruments as of June 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 June 30, 2017                 Assets                 Oil derivative contracts – current   $ —   $ 3,473   $ 99   $ 3,572 Oil derivative contracts – long-term   —   1,237   —   1,237 Total Assets   $ —   $ 4,710   $ 99   $ 4,809                   Liabilities                 Oil derivative contracts – long-term   $ —   $ (407 )   $ —   $ (407 ) Total Liabilities   $ —   $ (407 )   $ —   $ (407 )                   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 six months ended June 30, 2017 and 2016:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Fair value of Level 3 instruments, beginning of period   $ 91   $ 23,040   $ (526 )   $ 52,834 Fair value gains (losses) on commodity derivatives   8   (4,818 )   625   (4,536 ) Receipts on settlements of commodity derivatives   —   (17,982 )   —   (48,058 ) Fair value of Level 3 instruments, end of period   $ 99   $ 240   $ 99   $ 240                   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   $ 8   $ (3,857 )   $ 245   $ (3,870 ) We utilize an income approach to value our Level 3 costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:     Fair Value at 6/30/2017 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 99   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2017   18.4% – 32.6% 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 June 30, 2017 and December 31, 2016, excluding pipeline financing and capital lease obligations, was $1,973.8 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.

v3.7.0.1

Commitments and Contingencies	6 Months Ended
	Jun. 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. In June 2017, MSPC announced the immediate suspension of startup and operations activities of the lignite coal gasification portion of the Kemper County energy facility, resulting in no further sale of CO2 to us while operation of the lignite coal gasification portion of the facility is suspended. 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 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.

v3.7.0.1

Additional Balance Sheet Details	6 Months Ended
	Jun. 30, 2017
Disclosure Text Block [Abstract]
Additional Balance Sheet Details	Note 8. Additional Balance Sheet Details Trade and Other Receivables, Net     June 30,   December 31, In thousands   2017   2016 Trade accounts receivable, net   $ 17,211   $ 20,084 Federal income tax receivable   11,271   — Other receivables   31,911   23,816 Total   $ 60,393   $ 43,900

v3.7.0.1

Subsequent Event	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
Subsequent Event	Note 9. Subsequent Events Employee Equity Award Grants On July 11, 2017, the Compensation Committee of our Board of Directors granted customary long-term equity incentive awards covering 4,656,823 shares of restricted stock to our employees under our 2004 Omnibus Stock and Incentive Plan. The closing price of Denbury’s common stock on July 11, 2017 was $1.52 per share. The awards generally vest one-third per year over a three-year period. Assets Held for Sale During July 2017, we signed an exclusive listing agreement to begin actively marketing for sale certain non-productive surface acreage ideally suited for commercial development in the Houston area, which we currently anticipate selling during the next 12 months, although no such sale is assured. This acreage was acquired through a combination of certain producing oilfield acquisitions and separate land purchases, and as of June 30, 2017, the carrying value of the land was $33.1 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.

v3.7.0.1

Basis of Presentation (Policies)	6 Months Ended
	Jun. 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 June 30, 2017, our consolidated results of operations for the three and six months ended June 30, 2017 and 2016, and our consolidated cash flows for the six months ended June 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 six months ended June 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   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   389,904   370,566   389,652   358,901 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,923   —   2,762   — Diluted weighted average common shares outstanding   391,827   370,566   392,414   358,901 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 six months ended June 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   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,785   6,265   4,914   6,839 Restricted stock and performance-based equity awards   7,655   4,374   4,442   4,491
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 $479.4 million and $256.0 million during the three months ended June 30 and March 31, 2016, respectively. We did not record a ceiling test write-down during the three or six months ended June 30, 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, for discussion of the impact ASU 2017-01 had on our current period consolidated financial statements. 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 in the process of reviewing our various revenue contracts to determine the impact of adoption of this new guidance and has not yet determined the effect this standard will have on our consolidated financial statements.
Commodity Derivative Contracts	We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change.  These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations. Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps and fixed-price swaps enhanced with a sold put. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis.  We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, 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 fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. • Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 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 $9 thousand in the fair value of these instruments as of June 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.

v3.7.0.1

Basis of Presentation (Tables)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Weighted average shares used in the basic and diluted net loss per common share	The following is a reconciliation of the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Basic weighted average common shares outstanding   389,904   370,566   389,652   358,901 Potentially dilutive securities                 Restricted stock and performance-based equity awards   1,923   —   2,762   — Diluted weighted average common shares outstanding   391,827   370,566   392,414   358,901
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Stock appreciation rights   4,785   6,265   4,914   6,839 Restricted stock and performance-based equity awards   7,655   4,374   4,442   4,491

v3.7.0.1

Long-Term Debt (Tables)	6 Months Ended
	Jun. 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:     June 30,   December 31, In thousands   2017   2016 Senior Secured Bank Credit Agreement   $ 490,000   $ 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 $2 and $3, respectively   2,252   2,253 Pipeline financings   197,726   202,671 Capital lease obligations   38,829   48,718 Total debt principal balance   2,954,079   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   (14,259 )   (15,641 ) Total debt, net of debt issuance costs   3,143,506   2,993,098 Less: current maturities of long-term debt (1)   (83,458 )   (83,366 ) Long-term debt and capital lease obligations   $ 3,060,048   $ 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 June 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.

v3.7.0.1

Commodity Derivative Contracts (Tables)	6 Months Ended
	Jun. 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 June 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 Three-Way Collars (2)                               July – Sept   NYMEX   14,500   $ 40.00 – 70.25   $ —   $ 30.00   $ 40.00   $ 69.09 July – Sept   LLS   2,000     41.00 – 69.25   —   31.00   41.00   69.25 Oct – Dec   NYMEX   11,000     40.00 – 70.20   —   30.00   40.00   69.67 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   3,000   $ 50.12 – 50.25   $ 50.20   $ —   $ —   $ — 2018 Three-Way Collars (2)                               Jan – Dec   NYMEX   6,000   $ 45.00 – 56.60   $ —   $ 36.25   $ 46.25   $ 55.08 (1) Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars and three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. (2) A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes.

v3.7.0.1

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 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 June 30, 2017                 Assets                 Oil derivative contracts – current   $ —   $ 3,473   $ 99   $ 3,572 Oil derivative contracts – long-term   —   1,237   —   1,237 Total Assets   $ —   $ 4,710   $ 99   $ 4,809                   Liabilities                 Oil derivative contracts – long-term   $ —   $ (407 )   $ —   $ (407 ) Total Liabilities   $ —   $ (407 )   $ —   $ (407 )                   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 six months ended June 30, 2017 and 2016:     Three Months Ended   Six Months Ended     June 30,   June 30, In thousands   2017   2016   2017   2016 Fair value of Level 3 instruments, beginning of period   $ 91   $ 23,040   $ (526 )   $ 52,834 Fair value gains (losses) on commodity derivatives   8   (4,818 )   625   (4,536 ) Receipts on settlements of commodity derivatives   —   (17,982 )   —   (48,058 ) Fair value of Level 3 instruments, end of period   $ 99   $ 240   $ 99   $ 240                   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   $ 8   $ (3,857 )   $ 245   $ (3,870 )
Quantitative valuation techniques for assets and liabilities measured on a recurring basis (Level 3)	The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:     Fair Value at 6/30/2017 (in thousands)   Valuation Technique   Unobservable Input   Volatility Range Oil derivative contracts   $ 99   Discounted cash flow / Black-Scholes   Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2017   18.4% – 32.6%

v3.7.0.1

Additional Balance Sheet Details (Tables)	6 Months Ended
	Jun. 30, 2017
Table Text Block [Abstract]
Trade and Other Receivables, Net	Trade and Other Receivables, Net     June 30,   December 31, In thousands   2017   2016 Trade accounts receivable, net   $ 17,211   $ 20,084 Federal income tax receivable   11,271   — Other receivables   31,911   23,816 Total   $ 60,393   $ 43,900

v3.7.0.1

Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Weighted average shares used in the basic and diluted net income per common share
Basic weighted average common shares outstanding	389,904	370,566	389,652	358,901
Potentially dilutive securities
Restricted stock and performance-based equity awards	1,923	0	2,762	0
Diluted weighted average common shares outstanding	391,827	370,566	392,414	358,901

v3.7.0.1

Basis of Presentation (Antidilutive Securities) (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 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	4,785	6,265	4,914	6,839
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	7,655	4,374	4,442	4,491

v3.7.0.1

Basis of Presentation (Details Textuals) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2017	Jun. 30, 2016
Accounting Policies [Abstract]
Write-down of oil and natural gas properties	$ 0	$ 479,400	$ 256,000	$ 0	$ 735,400

v3.7.0.1

Asset Acquisition (Details Textuals) $ in Millions	Jun. 30, 2017 USD ($)
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Non-operated working interest acquired in asset acquisition	23.00%
Costs Incurred, Acquisition of Oil and Gas Properties	$ 71.5

v3.7.0.1

Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands		Jun. 30, 2017	Dec. 31, 2016	May 31, 2016
Debt Instrument [Line Items]
Senior Secured Bank Credit Agreement		$ 490,000	$ 301,000
Pipeline financings		197,726	202,671
Capital lease obligations		38,829	48,718
Total debt principal balance		2,954,079	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		3,143,506	2,993,098
Less: current maturities of long-term debt	[1]	(83,458)	(83,366)
Long-term debt and capital lease obligations		3,060,048	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		$ (50,500)
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		$ (14,259)	(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		$ 2,252	2,253
Including premium of		$ 2	$ 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 June 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.

v3.7.0.1

Long-Term Debt (Details Textuals)	1 Months Ended	3 Months Ended			6 Months Ended
	May 31, 2016 USD ($) shares	Jun. 30, 2017 USD ($) shares	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2017 USD ($) shares	Jun. 30, 2016 USD ($)	Aug. 07, 2017 USD ($)	Dec. 31, 2016 USD ($) shares
Long Term Debt (Textuals) [Abstract]
Interest in guarantor subsidiaries		100.00%			100.00%
Debt Instrument, Repurchased Face Amount				$ 152,300,000
Debt Instrument, Repurchase Amount				55,500,000
Gain on debt extinguishment		$ 0	$ 12,278,000	95,000,000	$ 0	$ 107,269,000
Debt Conversion, Original Debt, Amount	$ 1,057,800,000
Common Stock, Shares, Issued | shares	40,700,000	403,305,493			403,305,493			402,334,655
Extinguishment of Debt, Amount	$ 442,900,000
Senior Secured Bank Credit Facility [Abstract]
Line of Credit, Borrowing Base		$ 1,050,000,000.00			$ 1,050,000,000.00
Line of Credit Facility, Current Borrowing Capacity		1,050,000,000.00			$ 1,050,000,000.00
Weighted average interest rate on Bank Credit Facility					4.20%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					0.50%
Current Ratio Requirement					1.0
Subsequent Event [Member]
Senior Secured Bank Credit Facility [Abstract]
Senior subordinated notes available for repurchase or other redemptions							$ 148,300,000
9% Senior Secured Second Lien Notes Due 2021
Long Term Debt (Textuals) [Abstract]
9% Senior Secured Second Lien Notes due 2021	614,919,000	$ 614,919,000			$ 614,919,000			$ 614,919,000
Senior Subordinated Notes | 6 3/8% Senior Subordinated Notes due 2021
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount				4,000,000
Debt Conversion, Original Debt, Amount	175,100,000
Senior Subordinated Notes | 5 1/2% Senior Subordinated Notes due 2022
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount				42,300,000
Debt Conversion, Original Debt, Amount	411,000,000
Senior Subordinated Notes | 4 5/8% Senior Subordinated Notes due 2023
Long Term Debt (Textuals) [Abstract]
Debt Instrument, Repurchased Face Amount				$ 106,000,000
Debt Conversion, Original Debt, Amount	$ 471,700,000
Year 2017 | Q3
Senior Secured Bank Credit Facility [Abstract]
Senior Secured Debt to Consolidated EBITDAX		3.0
Consolidated EBITDAX to Consolidated Interest Charges		1.25
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%

v3.7.0.1

Income Taxes (Details) - USD ($)	24 Months Ended
	Dec. 31, 2016	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local		$ 36,500,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 36,500,000
Unrecognized Tax Benefits		$ 5,400,000
Deferred Tax Assets, Net of Valuation Allowance	$ 0

v3.7.0.1

Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details)	Jun. 30, 2017 bbl / d $ / Barrel
Three-way Collar | Year 2017 | Q3 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	14,500
Derivative, Floor Price	40.00
Derivative, Cap Price	70.25
Weighted average sold put price	30.00
Weighted average floor price	40.00
Weighted average ceiling price	69.09
Three-way Collar | Year 2017 | Q3 | LLS
Derivative [Line Items]
Volume per day | bbl / d	2,000
Derivative, Floor Price	41.00
Derivative, Cap Price	69.25
Weighted average sold put price	31.00
Weighted average floor price	41.00
Weighted average ceiling price	69.25
Three-way Collar | Year 2017 | Q4 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	11,000
Derivative, Floor Price	40.00
Derivative, Cap Price	70.20
Weighted average sold put price	30.00
Weighted average floor price	40.00
Weighted average ceiling price	69.67
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	6,000
Derivative, Floor Price	45.00
Derivative, Cap Price	56.60
Weighted average sold put price	36.25
Weighted average floor price	46.25
Weighted average ceiling price	55.08
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
Swap | Year 2018 | NYMEX
Derivative [Line Items]
Volume per day | bbl / d	3,000
Weighted average swap price	50.20
Swap | Year 2018 | NYMEX | Minimum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	50.12
Swap | Year 2018 | NYMEX | Maximum
Derivative [Line Items]
Derivative, Swap Type, Fixed Price	50.25

v3.7.0.1

Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Oil derivative contracts - current asset	$ 3,572	$ 0
Oil derivative contracts - long-term	1,237	0
Total Assets	4,809
Oil derivative contracts - long-term liabilities	(407)	0
Oil derivative contracts - current liability	0	(69,279)
Total Liabilities	(407)	(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
Oil derivative contracts - long-term	0
Total Assets	0
Oil derivative contracts - long-term liabilities	0
Oil derivative contracts - current liability		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	3,473
Oil derivative contracts - long-term	1,237
Total Assets	4,710
Oil derivative contracts - long-term liabilities	(407)
Oil derivative contracts - current liability		(68,753)
Total Liabilities	(407)	(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	99
Oil derivative contracts - long-term	0
Total Assets	99
Oil derivative contracts - long-term liabilities	0
Oil derivative contracts - current liability		(526)
Total Liabilities	$ 0	$ (526)

v3.7.0.1

Fair Value Measurements (Level 3 Fair Value Measurements) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 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	$ 91	$ 23,040	$ (526)	$ 52,834
Fair value gains (losses) on commodity derivatives	8	(4,818)	625	(4,536)
Receipts on settlements of commodity derivatives	0	(17,982)	0	(48,058)
Fair value of Level 3 instruments, end of period	99	240	99	240
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	$ 8	$ (3,857)	$ 245	$ (3,870)

v3.7.0.1

Fair Value Measurements (Level 3 Valuation Techniques) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 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	$ 99	$ 91	$ (526)	$ 240	$ 23,040	$ 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	$ 99
Income Approach Valuation Technique | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	18.40%
Income Approach Valuation Technique | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Expected Volatility Range	32.60%

v3.7.0.1

Fair Value Measurements (Details Textuals) - USD ($) $ in Thousands	Jun. 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	$ 9
Debt, Fair Value	$ 1,973,800	$ 2,327,800

v3.7.0.1

Commitments and Contingencies (Details) - Helium Supply Arrangement [Member] $ in Millions	3 Months Ended
	Jun. 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

v3.7.0.1

Additional Balance Sheet Details (Trade and Other Receivables, Net Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Receivables [Abstract]
Trade accounts receivable, net	$ 17,211	$ 20,084
Federal income tax receivable	11,271	0
Other receivables	31,911	23,816
Total	$ 60,393	$ 43,900

v3.7.0.1

Subsequent Event (Details Textuals) - USD ($) $ / shares in Units, $ in Millions	Jul. 11, 2017	Jun. 30, 2017
Subsequent Event [Line Items]
Land Available-for-sale		$ 33.1
Subsequent Event [Member]
Subsequent Event [Line Items]
Restricted stock granted	4,656,823
Value (per share) of restricted stock grant	$ 1.52
Equity award vesting percentage	33.00%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

This regulatory filing also includes additional resources:
dnr-20170630x10q.pdf